Methods and system for creating high conductivity fractures

ABSTRACT

Methods for forming proppant pillars in a formation during formation fracturing include include periods of pumping a first fracturing fluid including a proppant and an aggregating composition including a reaction product of a phosphate compound or a plurality of phosphate and an amine, periods of pumping a second fracturing fluid excluding a proppant and an aggregating composition including a reaction product of a phosphate compound and periods of pumping a third fracturing fluid including an aggregating composition including a reaction product of a phosphate compound, where the pumping of the three fracturing fluids may be in any order and may involve continuous pumping, pulse pumping, or non-continuous pumping.

RELATED APPLICATIONS

The present invention claim provisional priority to and the benefit ofU.S. Provisional Patent Application Ser. No. 61/905,340 filed 18 Nov.2013 (11/18/2013)(18.11.2013) and continuations-in-part of U.S. patentapplication Ser. No. 12/690,292 filed Jan. 20, 2010, Ser. No. 13/914,513filed Jun. 10, 2013, Ser. No. 13/914,526 filed Jun. 10, 2013, and Ser.No. 14/308,160 filed Jun. 18, 2014.

BACKGROUND OF THE INVENTION

1. Field of the Invention

Embodiments of this invention relate to methods for producing fluidsfrom subterranean formations through the formation of a network ofproppant pillars, clusters, columns, or islands in fractures in aformation during and/or after formation fracturing, proppant networks,and proppant pillars.

More particularly, embodiments of this invention relate to methods forproducing fluids from subterranean formations through the formation of anetwork of proppant pillars, clusters, columns, or islands in fracturesin a formation during and/or after formation fracturing, proppantnetworks, and proppant pillars, where the methods include a sequence ofproppant stages designed to form proppant networks and proppant pillarsthat increase fracture conductivity.

2. Description of the Related Art

During fracturing applications, proppants are deposited in the fracturewith the aid of fracturing fluid to keep the fracture opened. Generallyproppant particles are placed in the fracture in concentrationssufficient to form a tight pack. When fractures close under pressure,this closure causes compaction, resulting in some of the proppantcrushing or proppant embedment into the fracture face. Both phenomenaresults in restricted flow paths through the fracture stimulated volumeand hence causes decreased fracture conductivity. The porosity of thepack decreases even more if the proppants are not of high strength,spherical or larger in size. Higher formation pressure also leads todecreased fracture conductivity.

Historically, many techniques have been proposed to get highconductivity fracture. For example, one techniques involves depositinglow volume of proppant in the fractures and creating a “partialmonolayer” to generate high conductivity. Proppants are placed far fromeach other, but are still able to keep fractures opened. Fluid flowaround widely spaced proppants. This is practiced by Halliburton usingplastic proppants and Baker Hughes using light weight or ultra-lightweight proppants, for example, walnut hull. For another example,Schlumberger used channel hydraulic fracturing technique also called“HiWay” frac to create open pathways within the proppant pack, byintermittently pumped slugs of proppants during fracturing with fibersto form islands of proppants or pillars in the fractures. The engineeredchannels provide highly conductive paths for flow of fluids in thefractured formation. For another example, Halliburton described usingproppants coated with adhesive substance at lower concentration to makethe higher conductivity fractures. For yet another example, Halliburtondescribed introducing degradable materials in the proppant pack, whichover time degrade to provide higher porosity fractures. Many othertechniques to form high porosity fractures has also been proposed, usedor introduced.

While many inventions have been used to achieve high conductivityfractures that have a reduced tendency to collapse under high pressureproduction conditions, the present invention describes methods to createhigh conductivity fracture by increasing porosity using zeta potentialaltering chemistries and proppants introduced under fracturingconditions, where the conditions are sufficient to produce proppantpillars within a fractured formation through sequences of injections ofdifferent fracturing fluids into a formation some including no proppantand no aggregating or zeta altering compositions, some including noproppant, but aggregating or zeta altering compositions, and someincluding both proppants and aggregating or zeta altering compositions.

SUMMARY OF THE INVENTION

Embodiments of this invention provide methods for achieving highconductivity fractures within a formation being fractured usingproppants and a zeta altering or aggregating composition. In certainembodiments, the zeta altering or aggregating composition is pumped withthe fracturing fluid and the proppant into the formation duringfracturing treatment. The zeta altering or aggregating composition coatsor partially coats the proppant particles such as sand changing the zetapotential or aggregating propensity of the proppant particles causingthe particles to aggregate or agglomerate into distinct pillars information fractures permitting lower concentrations of proppants neededto prop open the fractures and creating highly conductive fractures.These agglomerated pillars provide enough strength to keep the fracturesopened during production leading to greater conductivity in thefractures. In other embodiments, the proppant is pre-treated with thezeta altering or aggregating composition to form a coated or partiallycoated proppant particles such as coated or partially coated sandparticles before adding the proppant to the fracturing fluid and thenpumping the resulting fracturing fluid into the formation underfracturing conditions. The coated or partially coated proppant particlesagglomerate or aggregate into clusters permitting lower proppantconcentrations to be used to fill the fractures formed duringfracturing. In other embodiments, the proppant is pre-treated with thezeta altering or aggregating composition to form the coated or partiallycoated proppant particles such as coated or partially coated sandparticles and then intermittently adding the proppant to the fracturingfluid as the fluid is being pumped downhole into the formation underfracturing conditions to create islands or pillars of agglomeratedproppant particles (e.g., sand particles) in the fracture, thusachieving greater porosity and greater conductivity in the fracturedformation. In the present technique, the regions of pillars and channelsmay be formed by the intermittently pumping of the proppant, the zetaaltering or aggregating composition, and/or the pre-coated propant. Dueto the presence of the coating or partial coating of the proppantparticles with the zeta altering or aggregating composition, the regionof pillars have improved strength allowing the structure to remaintogether after fracturing and during production or injection. In othertechniques, it is suspected that the grains will not stay in place afterfracturing. The present technique may be used in slick water fracturingsystems, VES fracturing systems, linear gel fracturing systems,crosslinked fracturing systems or hybrid fracturing system using freshwater base fluids or brine base fluids.

Embodiments of this invention provide methods for forming proppantpillars in a formation during formation fracturing, where the methodsinclude periods of pumping a first fracturing fluid including a proppantand an aggregating composition including a reaction product of aphosphate compound or a plurality of phosphate and an amine, periods ofpumping a second fracturing fluid excluding a proppant and anaggregating composition including a reaction product of a phosphatecompound and periods of pumping a third fracturing fluid including anaggregating composition including a reaction product of a phosphatecompound, where the pumping of the three fracturing fluids may be in anyorder and may involve continuous pumping, pulse pumping, intermittentpumping, or non-continuous pumping. In certain embodiments, the methodsmay also include periods of hold times between pumping of the differentfluids into the formation.

Embodiments of this invention provide methods for forming proppantpillars in a formation during formation fracturing, where the methodsinclude a sequence of injections of one fracturing fluid or a pluralityof different fracturing fluids, where the fracturing fluids are selectedfrom the group consisting of fluids that include a proppant and a zetaaltering or aggregating composition, fluids that do not include theproppant and the zeta altering or aggregating composition, fluids thatinclude the zeta altering or aggregating composition, but no proppant,and fluids that include a proppant, but no zeta altering or aggregatingcomposition. The sequences may include single injections of each fluidin any order or multiple injections of each fluid in any order. Thus,one sequence may include injecting a first fluid including no proppant,injection a second fluid including the zeta altering or aggregatingcomposition, but no proppant, and a third fluid including the proppantand the zeta altering or aggregating composition. The fluids including aproppant may include untreated proppant, treated proppant comprisingparticles coated or partially coated with the zeta altering oraggregating composition, or mixtures thereof. Another sequence mayinclude a plurality of first fluid injections, a plurality of secondfluid injections, and a plurality of third fluid injections. Anothersequence may include single injections of the first, second, and thirdfluids repeated a number of times during the course of the proppantplacement stage of a fracturing operation. Another sequence may includemultiple injections of each fluid in any given order. The sequence mayalso include a hold period between each injection. Thus, a sequence mayinclude a first fluid injection, a first hold time, a second fluidinjection, a second hold time, and a third fluid injection, and a thirdhold time, where the first, second and third fluid may be any of thefluid compositions listed above.

Embodiments of methods of this invention provide a proppant placementstep involving injecting alternating slugs of proppant-free fluids andproppant-containing fluids into fractures of the fracturing layer abovefracturing pressure through a number of perforation groups. The slugs ofproppant-containing fluids form proppant pillars, clusters, or islandsin the fractures during fracturing and/or after fracturing as thefractures closes.

Embodiments of methods of this invention provide a proppant placementstep involving injecting alternating slugs of proppant-free fluids andproppant-containing fluids into the fractures of the fracturing layerabove fracturing pressure through a number of perforation groups in awellbore, and causing the sequences of slugs of proppant-free fluids andproppant-containing fluids injected through neighboring perforationgroups to move through the fractures at different rates. The slugs ofproppant-containing fluids again form proppant pillars, clusters, orisland in the fractures during fracturing and/or after fracturing as thefractures closes.

Embodiments of methods of this invention provide a proppant placementstep involving injecting alternating slugs of proppant-free fluids andproppant-containing fluids into the fractures of the fracturing layerabove fracturing pressure through a number of perforation groups in awellbore, and causing the sequences of slugs of proppant-free fluids andproppant-containing fluids injected through at least one pair ofperforation groups to be separated by a region of injected proppant-freefluids. Again, the slugs of proppant-containing fluids form proppantpillars, clusters, or islands in the fractures during fracturing and/orafter fracturing as the fractures closes.

There are many optional variations of these methods including, withoutlimitation, (i) varying the proppant-free fluids in some or all of theproppant-free fluid slugs, (ii) varying the proppant-containing fluidsin some or all of the proppant-containing fluid slugs, (iii) varying theproppant composition in some or all of the proppant-containing fluids,(iv) varying slug properties of some or all of the slugs, (v) varyingthe sequence of slugs, (vi) varying the number of perforation groups,(vii) varying the perforation group separations, (viii) varying a lengthof some or all of the group lengths, (ix) varying a number ofperforation in some or all of the groups, or (xii) varying other fluidproperties, other slug properties, other fracturing properties, etc.

In other variations, the methods may have a step following the proppantplacement step involving continuous introduction of aproppant-containing fluid into the fracturing fluid, where the proppanthas an essentially uniform particle size. This following step mayinclude a reinforcing material, a proppant transport material, othermaterials, or mixtures thereof. The fluids may be viscosified with apolymer or with a viscoelastic surfactant. The number of holes in eachperforation group may be the same or different. The diameter of holes inall of the groups may be the same or different. The lengths of theperforation groups and the spans separating the groups may be the sameor different. At least two different perforation group forming methodsmay be used. Some of the groups may be produced using an underbalancedperforation technique or an overbalanced perforation technique. Theorientations of the perforations in all of the groups relative to thepreferred fracture plane may be the same or different.

In another variation, pairs of groups that produce slug pulses in theformation may be separated by a perforation group having sufficientlysmall perforations that the proppant bridges and proppant-free fluidenters the formation therethrough. Generally, a number of perforation ineach group is between 2 and 300; in certain embodiments, the number maybe between 2 and 100. Generally, the perforation group length betweenadjacent groups is between 0.15 m and 3.0 m; in certain embodiments thegroup length is from 0.30 m to 30 m. Generally, the perforation shotdensity is from 1 to 30 shots per 0.3. Generally, theproppant-containing slugs have a volume between 80 liters and 16,000liters.

In certain embodiments, the fluid injection sequence is determined froma mathematical model; and/or the fluid injection sequence includes acorrection for slug dispersion; and/or the perforation pattern isdetermined from a mathematical model.

In other embodiments, at least one of the parameters including slugvolume, slug composition, proppant composition, proppant size, proppantconcentration, number of holes per perforation group, perforation grouplength, perforation group separation, perforation group orientation,perforation group shot density, lengths of perforation groups, methodsof perforation, is constant along the wellbore in the fracturing layer,or increases or decreases along the wellbore in the fracturing layer, oralternates along the wellbore in the fracturing layer.

The methods of this invention are designed to allow proppant pillars,clusters, or islands to form in the fractures such that the proppantpillars do not extend across an entire dimension of the fracturesparallel to the wellbore including regions of proppant pillars,clusters, or islands interrupted by flow channels or pathways betweenthe pillars form pathways that lead to the wellbore, i.e., the proppantpillars, clusters, or islands are separated in a distribution in thefractures to form the flow channels or pathways. In certain embodiments,the proppant compositions and the proppant placement step are designedto lower an amount of proppant needed to achieve a desired level offracture conductivity greater than a fracture conductivity in theabsence of the proppant pillars, clusters, or islands formed in thefractures.

BRIEF DESCRIPTION OF THE DRAWINGS

The invention can be better understood with reference to the followingdetailed description together with the appended illustrative drawings inwhich like elements are numbered the same:

FIG. 1A depicts an embodiment of a fracturing profile of this invention.

FIG. 1B depicts another embodiment of a fracturing profile of thisinvention.

FIG. 1C depicts another embodiment of a fracturing profile of thisinvention.

FIG. 1D depicts another embodiment of a fracturing profile of thisinvention.

FIG. 2A depicts an embodiment a proppant pattern or network within aboard fracture.

FIG. 2B depicts an embodiment a proppant pattern or network within anarrow fracture.

FIG. 2C depicts an embodiment a proppant pattern or network within anillustrative square fracture.

FIG. 2D depicts an embodiment a proppant pattern or network within abranched fracture.

FIG. 2E depicts an embodiment a proppant pattern or network within afrac pack.

FIGS. 3A-I depict nine different illustrative proppant clusters.

FIGS. 4A-J depict ten different proppant groups of proppant clusters.

FIGS. 5A-D depict four different perforation patterns.

FIG. 6 depicts a table of zeta potentials and aggregating propensitiesand a plot of zeta potentials for untreated silica and coal and treatedsilica and coal.

DEFINITIONS OF TERM USED IN THE INVENTION

The following definitions are provided in order to aid those skilled inthe art in understanding the detailed description of the presentinvention.

The term “about” means that the value is within about 10% of theindicated value. In certain embodiments, the value is within about 5% ofthe indicated value. In certain embodiments, the value is within about2.5% of the indicated value. In certain embodiments, the value is withinabout 1% of the indicated value. In certain embodiments, the value iswithin about 0.5% of the indicated value.

The term “substantially” means that the value is within about 10% of theindicated value. In certain embodiments, the value is within about 5% ofthe indicated value. In certain embodiments, the value is within about2.5% of the indicated value. In certain embodiments, the value is withinabout 1% of the indicated value. In certain embodiments, the value iswithin about 0.5% of the indicated value.

The term “proppant pillar, proppant island, proppant cluster, proppantaggregate, or proppant agglomerate” mean that a plurality of proppantparticles are aggregated, clustered, agglomerated or otherwise adheredtogether to form discrete structures.

The term “mobile proppant pillar, proppant island, proppant cluster,proppant aggregate, or proppant agglomerate” means proppant pillar,proppant island, proppant cluster, proppant aggregate, or proppantagglomerate that are capable of repositioning during fracturing,producing, or injecting operations.

The term “self healing proppant pillar, proppant island, proppantcluster, proppant aggregate, or proppant agglomerate” means proppantpillar, proppant island, proppant cluster, proppant aggregate, orproppant agglomerate that are capable of being broken apart andrecombining during fracturing, producing, or injecting operations.

The term “premature breaking” as used herein refers to a phenomenon inwhich a gel viscosity becomes diminished to an undesirable extent beforeall of the fluid is introduced into the formation to be fractured. Thus,to be satisfactory, the gel viscosity should preferably remain in therange from about 50% to about 75% of the initial viscosity of the gelfor at least two hours of exposure to the expected operatingtemperature. Preferably the fluid should have a viscosity in excess of100 centipoise (cP) at 100 sec⁻¹ while injection into the reservoir asmeasured on a Fann 50 C viscometer in the laboratory.

The term “complete breaking” as used herein refers to a phenomenon inwhich the viscosity of a gel is reduced to such a level that the gel canbe flushed from the formation by the flowing formation fluids or that itcan be recovered by a swabbing operation. In laboratory settings, acompletely broken, non-crosslinked gel is one whose viscosity is about10 cP or less as measured on a Model 35 Fann viscometer having a R1B1rotor and bob assembly rotating at 300 rpm.

The term “amphoteric” refers to surfactants that have both positive andnegative charges. The net charge of the surfactant can be positive,negative, or neutral, depending on the pH of the solution.

The term “anionic” refers to those viscoelastic surfactants that possessa net negative charge.

The term “fracturing” refers to the process and methods of breaking downa geological formation, i.e. the rock formation around a well bore, bypumping fluid at very high pressures, in order to increase productionrates from a hydrocarbon reservoir. The fracturing methods of thisinvention use otherwise conventional techniques known in the art.

The term “proppant” refers to a granular substance suspended in thefracturing fluid during the fracturing operation, which serves to keepthe formation from closing back down upon itself once the pressure isreleased. Proppants envisioned by the present invention include, but arenot limited to, conventional proppants familiar to those skilled in theart such as sand, 20-40 mesh sand, resin-coated sand, sintered bauxite,glass beads, and similar materials.

The abbreviation “RPM” refers to relative permeability modifiers.

The term “surfactant” refers to a soluble, or partially soluble compoundthat reduces the surface tension of liquids, or reduces inter-facialtension between two liquids, or a liquid and a solid by congregating andorienting itself at these interfaces.

The term “viscoelastic” refers to those viscous fluids having elasticproperties, i.e., the liquid at least partially returns to its originalform when an applied stress is released.

The phrase “viscoelastic surfactants” or “VES” refers to that class ofcompounds which can form micelles (spherulitic, anisometric, lamellar,or liquid crystal) in the presence of counter ions in aqueous solutions,thereby imparting viscosity to the fluid. Anisometric micelles inparticular are preferred, as their behavior in solution most closelyresembles that of a polymer.

The abbreviation “VAS” refers to a Viscoelastic Anionic Surfactant,useful for fracturing operations and frac packing. As discussed herein,they have an anionic nature with preferred counterions of potassium,ammonium, sodium, calcium or magnesium.

The term “foamable” means a composition that when mixed with a gas formsa stable foam.

The term “fracturing layer” is used to designate a layer, or layers, ofrock that are intended to be fractured in a single fracturing treatment.It is important to understand that a “fracturing layer” may include oneor more than one of rock layers or strata as typically defined bydifferences in permeability, rock type, porosity, grain size, Young'smodulus, fluid content, or any of many other parameters. That is, a“fracturing layer” is the rock layer or layers in contact with all theperforations through which fluid is forced into the rock in a giventreatment. The operator may choose to fracture, at one time, a“fracturing layer” that includes water zones and hydrocarbon zones,and/or high permeability and low permeability zones (or even impermeablezones such as shale zones) etc. Thus a “fracturing layer” may containmultiple regions that are conventionally called individual layers,strata, zones, streaks, pay zones, etc., and we use such terms in theirconventional manner to describe parts of a fracturing layer. Typicallythe fracturing layer contains a hydrocarbon reservoir, but the methodsmay also be used for fracturing water wells, storage wells, injectionwells, etc. Note also that some embodiments of the invention aredescribed in terms of conventional circular perforations (for example,as created with shaped charges), normally having perforation tunnels.However, the invention is may also be practiced with other types of“perforations”, for example openings or slots cut into the tubing byjetting.

The term “gpt” means gallons per thousand gallons.

The term “ppt” means pounds per thousand gallons.

DETAILED DESCRIPTION OF THE INVENTION

The inventors have found that by changing a zeta potential oraggregating propensity of proppants such as sand using a zeta alteringor aggregating composition such as SandAid™ available from Weatherford,the proppants will tend to aggregate and/or agglomerate in fractures ofa formation during and/or after fracturing to form discrete pillarspermitting a lower concentration of proppant particles to be pumpeddownhole during fracturing. The aggregation and/or agglomerationcomposition provides higher strength pillars to form in the fractureshaving a reduced tendency to be crushed under forces encountered duringproduction. Unlike prior art treatments, where partial monolayers areformed on proppant particles are used for propping open fractures thatare not able to withstand the crush force encountered during production,the zeta altering or aggregating compositions of this invention modifythe aggregation and/or agglomeration particles to improve pillar crushstrength and pillar aggregation propensity. Also, embedding proppant inthe formation tends to choke the permeability, and, therefore, thesetechnique are not widely used. In Hiway fracturing technique, theclusters are formed by intermittent adding of particles to fracturingfluid with fibers. The fibers help to suspend the proppants, but it issuspected that the clusters formed do not remain together to formconductive channels. On the other hand, in the present invention, we arecertain that the proppant (e.g., sand) agglomeration with zeta alteringor aggregating composition keep the clusters of agglomerated particlesdiscreet and in tact. The added advantage of this technique is that itwill prevent fines migration by capturing fines and thus preventing theporosity to go down over time.

The inventors have found that using both chemistry and pumping techniqueadvanced pillar type fracturing structures may be produced in theformation. This advanced pillar formation will permit maximization offluid flow from the well because the advanced pillar formation increasesconductivity.

It is the use of the zeta altering chemistry to ensure that thechannels/pillars are efficiently formed and have greater strength towithstand erosion and proppant migration as compared to the othertechnologies previously disclosed. Prior art solutions tochanninventions involve the use of dissolvable fibers which help withchannel/pillar formation but it has been observed that once the wellsare brought back on production with even minimal flux rate thechannels/pillars lose their strength once the fibers have been dissolvedand the channels collapse and the pillars erode leaving a conventionalfrac pac that will likely exhibit proppant migration and flow back.

The inventors have found that a composition can be produced that, whenadded to a particulate metal-oxide-containing solid or other solidmaterials or to a suspension or dispersion including a particulatemetal-oxide-containing solid or other solid materials, the particles aremodified so that an aggregation propensity, aggregation potential and/ora zeta potential of the particles are altered. The inventors have alsofound that metal-oxide-containing solid particles or other solidparticles can be prepared having modified surfaces or portions thereof,where the modified particles have improved aggregation tendencies and/orpropensities and/or alter particle zeta potentials. The inventors havealso found that the compositions and/or the modifiedmetal-oxide-containing solid or other solid particles can be used in oilfield applications including drilling, fracturing, producing, injecting,sand control, or any other downhold application. The inventors have alsofound that the modified particulate metal-oxide-containing solidparticles or particles of any other solid material can be used any otherapplication where increased particle aggregation potentials aredesirable or where decreased absolute values of the zeta potential ofthe particles, which is a measure of aggregation propensity. Theinventors have also found that a coated particulatemetal-oxide-containing solid compositions can be formed, where thecoating is deformable and the coated particles tend to self-aggregateand tend to cling to surfaces having similar coatings or having similarchemical and/or physical properties to that of the coating. That is tosay, that the coated particles tend to prefer like compositions, whichincrease their self-aggregation propensity and increase their ability toadhere to surface that have similar chemical and/or physical properties.The inventors have found that the coating compositions of this inventionare distinct from known compositions for modifying particle aggregationpropensities and that the coated particles are ideally suited asproppants, where the particles have altered zeta potentials that changethe charge on the particles causing them to attract and agglomerate. Thechange in zeta potential or aggregation propensity causes each particleto have an increased frictional drag keeping the proppant in thefracture. The compositions are also ideally suited for decreasing finesmigrating into a fracture pack or to decrease the adverse impact offines migration into a fractured pack.

The embodiments will be described for conventional hydraulic fracturing,but it is to be understood that embodiments of the invention also mayinclude water fracturing and frac packing. It should also be understoodthat throughout this specification, when a concentration or amount rangeis described as being useful, or suitable, or the like, it is intendedthat any and every concentration or amount within the range, includingthe end points, is to be considered as having been stated. Furthermore,each numerical value should be read once as modified by the term “about”(unless already expressly so modified) and then read again as not to beso modified unless otherwise stated in context. For example, “a range offrom 1 to 10” is to be read as indicating each and every possible numberalong the continuum between about 1 and about 10. In other words, when acertain range is expressed, even if only a few specific data points areexplicitly identified or referred to within the range, or even when nodata points are referred to within the range, it is to be understoodthat the inventors appreciate and understand that any and all datapoints within the range are to be considered to have been specified, andthat the inventors have possession of the entire range and all pointswithin the range.

In certain embodiments, the methods include periods of pumping differentfracturing fluid into of fractures of a formation, where the pumping ofthe fluids may be in any order and may involve continuous pumping, pulsepumping, intermittent pumping, or non-continuous pumping, where thepumping may be under same or different fracturing conditions, where thefracturing conditions include at least temperature, temperature profile,pressure, pressure profile, injection rate, injection rate profile,injection volume, and injection volume profile, fluid composition, andfluid composition profile. In other embodiments, the methods may alsoinclude hold periods. In all of these methods, the periods may be thesame or different.

Some embodiments illustrating the invention will be described in termsof vertical fractures in vertical wells, but are equally applicable tofractures and wells of any orientation, as examples horizontal fracturesin vertical or deviated wells, or vertical fractures in horizontal ordeviated wells. The embodiments will be described for one fracture, butit is to be understood that more than one fracture may be formed at onetime. Embodiments will be described for hydrocarbon production wells,but it is to be understood that the Invention may be used for wells forproduction of other fluids, such as water or carbon dioxide, or, forexample, for injection or storage wells. The embodiments will bedescribed for conventional hydraulic fracturing, but it is to beunderstood that embodiments of the invention also may include waterfracturing and frac packing. It should also be understood thatthroughout this specification, when a concentration or amount range isdescribed as being useful, or suitable, or the like, it is intended thatany and every concentration or amount within the range, including theend points, is to be considered as having been stated. Furthermore, eachnumerical value should be read once as modified by the term “about”(unless already expressly so modified) and then read again as not to beso modified unless otherwise stated in context. For example, “a range offrom 1 to 10” is to be read as indicating each and every possible numberalong the continuum between about 1 and about 10. In other words, when acertain range is expressed, even if only a few specific data points areexplicitly identified or referred to within the range, or even when nodata points are referred to within the range, it is to be understoodthat the inventors appreciate and understand that any and all datapoints within the range are to be considered to have been specified, andthat the inventors have possession of the entire range and all pointswithin the range.

In certain embodiments, the proppant placement in fracturing offracturing layers is fracturing design, where the fracturing designincluding perforation pattern, fluid sequence, fluid compositions, etc.creates a superior placement of proppant pillars, clusters, or islandswithin the fractures to increase, optimize or maximize an amount of open(void) space or flow pathwayes in the fractures. This, in turn, ensuresincreased, optimized, or maxized hydraulic conductivity of the fracturesand enhanced hydrocarbon production from a reservoir layer. The creationand placement of (a) proppant pillars, clusters, or islands, (b) regionsof proppant pillars, clusters, or islands, (c) flow pathways orchannels, or (d) regions of flow pathways or channels in the fractureshave the advantages of producing (a) longer (and/or higher) fractureswith the same mass of proppant, and (b) more effective fracture clean-upof fracturing fluids from the fractures due to a greater volume of thefracture being flow pathways.

The perforation design is particularly effective when used incombination with proppant slug blends engineered to minimize slugdispersion during their transport through the hydraulic fractured, whichmay be achieved through the use of the proppant compositions andaggregating compositions of this invention.

Generally, the fracturing operation includes a first stage including theinjection of a pad fluid into the formation (normally proppant-freeviscosified fluid), which initiates fracture formation and furthersfracture propagation. A second stage of the fracturing operationgenerally includes a number of sub-stages. During each sub-stage, aproppant-containing fluid slug having a given (designed or calculated)proppant composition and concentration is pumped (called a slugsub-stage) into the formation followed by a proppant-free fluid intervalsub-stage. The volumes of both proppant-containing fluid slugs andproppant-free fluid slugs significantly affects hydraulic conductivityof the fractures due to the formation and placement of proppant pillars,clusters, or islands in the fractures. The sequence ofproppant-containing and proppant-free fluid slugs may be repeated thenecessary number of times to achieve a desired pillar distributionand/or placement in the fractures. A duration of each sub-stage, theproppant composition, the proppant concentration, and the nature of thefluid in each slug may varied or optimized to increase, optimize ormaximize proppant pillar, cluster, or island placement resulting inincreased, improved, optimized or maximized fracture conductivity.

At the end of the treatment a heterogeneous proppant structure may beformed in the fractures. Following fracture closure, proppant pillarssqueeze and form stable proppant formations (pillars) between thefracture walls and prevent the fracture from complete closure.

In the hydraulic fracturing methods of this invention for fracturing asubterranean formation, the fracturing sequence generally includes afirst stage or “pad stage”, that involves injecting a fracturing fluidinto a borehole at a sufficiently high flow rate that it createshydraulic fractures in the formation. The pad stage is pumped so thatthe fractures will be of sufficient dimensions to accommodate thesubsequent slug including proppant-containing fluids. The volume andviscosity of the pad may be designed by those knowledgeable in the artof fracture design (for example, see “Reservoir Stimulation” 3^(rd) Ed.M. J. Economides, K. G. Nolte, Editors, John Wiley and Sons, New York,2000).

Water-based fracturing fluids are common, with natural or syntheticwater-soluble polymers added to increase fluid viscosity and are usedthroughout the pad and subsequent propped stages. These polymersinclude, but are not limited to, guar gums: (high molecular-weightpolysaccharides composed of mannose and galactose sugars) or guarderivatives, such as hydroxypropyl guar, carboxymethyl guar, andcarboxymethylhydroxypropyl guar. Cross-linking agents based on boron,titanium, zirconium or aluminum complexes are typically used to increasethe polymer's effective molecular weight, making it better suited foruse in high-temperature wells.

The second stage or “proppant stage” of a fracturing operation involvesintroduction into a fracturing fluid of a proppant in the form of solidparticles or granules to form a suspension or slury. The propped stagemay be divided into a sequence of slugs of different fracturing fluidsincluding non-viscosified proppant-free fluids, viscosifiedproppant-free fluids, non-viscosified proppant-containing fluids, orviscosified proppant-containing fluids. The sequence may include two ormore periodically repeated sub-stages including “carrier sub-stages”involving the injection of the proppant-free fracturing fluids, and“proppant sub-stages” involving the injection of proppant-containingfracturing fluids. As a result of the periodic (but not continual)slugging of slurry containing granular propping materials, the proppantdoes not completely fill the fracture. Rather, the proppant formclusters, posts, pillars, or islands with channels or flow pathwaystherebetween through which formation or injection fluids may pass. Thevolumes of proppant sub-stages and carrier sub-stages as pumped may bedifferent. That is, the volume of the carrier sub-stages may be largeror smaller than the volume of the proppant sub-stages. Furthermore, thevolumes of the sub-stages may change over time. For example, a proppantsub-stage pumped early in the treatment may be of a smaller volume thana proppant sub-stage pumped latter in the treatment. The relative volumeof the sub-stages is selected based on how much of the surface area ofthe fracture is to be supported by the proppant clusters, pillars,columns, or islands, and how much of the fracture area is to be openchannels through which formation fluids are free to flow.

In certain embodiments, the proppant composition in the slugs mayinclude reinforcing and/or consolidating materials to increase thestrength of the proppant clusters, pillars, columns, or islands formedand to prevent their collapse during fracture closure. Typically, thereinforcement material is added to some of the proppant sub-stages.Additionally, the concentrations of both proppant and the reinforcingmaterials may varied continuously, periodically, or intermittentlythroughout the proppant stage. As examples, the concentration ofreinforcing material and/or proppant may be different in two subsequentproppant sub-stages. It may also be suitable or practical in someapplications of the method to introduce the reinforcing material in acontinuous fashion throughout the proppant stage, both during thecarrier and proppant sub-stages. In other words, introduction of thereinforcing material may not be limited only to the proppant sub-stage.In certain embodiments, the concentration of the reinforcing materialdoes not vary during the entire proppant stage; monotonically increasesduring the proppant stage; or monotonically decreases during theproppant stage.

Curable, or partially curable, resin-coated proppant may be used asreinforcing and consolidating material to form proppant clusters. Theselection of the appropriate resin-coated proppant for a particularbottom hole static temperature (BHST) and for a particular fracturingfluid are well known to experienced workers. In addition, organic and/orinorganic fibers may be used to reinforce the proppant cluster. Thesematerials may be used in combination with resin-coated proppants orseparately. These fibers may be modified to have an adhesive coatingalone, or an adhesive coating coated by a layer of non-adhesivesubstance dissolvable in the fracturing fluid as it passes through thefracture. Fibers made of adhesive material may be used as reinforcingmaterial, coated by a non-adhesive substance that dissolves in thefracturing fluid as it passes through the fracture at the subterraneantemperatures. Metallic particles are another preference for reinforcingmaterial and may be produced using aluminum, steel containing specialadditives that reduce corrosion, and other metals and alloys. Themetallic particles may be shaped to resemble a sphere and measure 0.1-4mm. In certain embodiments, fibers such as metallic particles used areof an elongated shape with an aspect ratio (length to width or diameter)of greater than 5:1, for example a length longer than 2 mm and adiameter of 10 to 200 microns. Additionally, plates of organic orinorganic substances, ceramics, metals or metal-based alloys may be usedas reinforcing material. These plates may be disk or rectangle-shapedand of a length and width such that for all materials the ratio betweenany two of the three dimensions is greater than 5 to 1.

Proppant and fluid choice are also adjustable factors in the methods ofthis invention. The proppant composition and fluid compositions arechosen to increase, optimize, or maximize a strength of proppantclusters, pillars, columns and islands within the fractures afterfracture closure. A proppant cluster should maintain a reasonableresidual thickness at the full fracture closure stress. This ensures anincrease in fluid flow through open channels formed between the proppantclusters. In this situation, the proppant pack permeability, as such, isnot decisive for increasing well productivity. Thus, a proppant clustermay be created successfully using sand whose particles are too weak foruse in standard hydraulic fracturing in the formation of interest. Aproppant cluster may also be made from sand that has a very wideparticle size distribution that would not be suitable for conventionalfracturing. This is an important advantage, because sand costssubstantially less than ceramic proppant. Additionally, destruction ofsand particles during application of the fracture closure load mightimprove the strength of clusters consisting of sand granules. This canoccur because the cracking/destruction of sand proppant particlesdecreases the cluster porosity and increases the proppant compactness.Sand pumped into the fracture to create proppant clusters does not needgood granulometric properties, that is, the usually desirable narrowdiameter distribution of particles. For example, to implement themethod, it may be suitable to use 50,000 kg of sand, of which 10,000 to15,000 kg have a diameter of particles from 0.002 to 0.1 mm, 15,000 to30,000 kg have a diameter of particles from 0.2 to 0.6 mm, and 10,000 to15,000 kg have a diameter of particles from 0.005 to 0.05 mm. It shouldbe noted that about 100,000 kg of a proppant more expensive than sandwould be necessary to obtain a similar value of hydraulic conductivityin the created fracture using the prior (conventional) methods ofhydraulic fracturing.

In certain embodiments, some or all of the proppant sub-stages includeslugs have proppant compositions including treated proppants and some orall of the carrier sub-stages have aggregating compositions of thisinvention that cause proppant particles to conglutinate.

In certain embodiments, the methods the fracturing operation may includea third stage or “tail-in stage” following the second state involvingcontinuous introduction of an amount of proppant. If employed, thetail-in stage of the fracturing operation resembles a conventionalfracturing treatment, in which a continuous bed of well-sortedconventional proppant is placed in the fracture relatively near to thewellbore. In certain embodiments, the tail-in stage is distinguishedfrom the second stage by the continuous placement of a well-sortedproppant, that is, a proppant with an essentially uniform size ofparticles. The proppant strength in the tail-in stage is sufficient toprevent proppant crushing (crumbling), when it is subjected to thestresses that occur upon fracture closure. The role of the proppant atthis stage is to prevent fracture closure and, therefore, to providegood fracture conductivity in proximity to the wellbore. The proppantsused in this third stage should have properties similar to conventionalproppants.

In certain embodiments, a fracturing operation design (the number, size,and orientation of perforations and the perforation distribution overthe pay zone) includes a perforation pattern that acts as a“slug-splitter” for a given proppant slug, even when injection is into asingle, homogeneous formation layer (that is, even when the fracturinglayer is a single, homogeneous formation layer). The perforation patternresult in the splitting of the proppant slugs pumped down the wellboreinto a predetermined number of separated smaller slugs within thefractures of a particular zone. The number of proppant slugs and thecorresponding completion design may be optimized to achieve superiorperformance of the created hydraulic fracture.

In certain embodiments, the methods of pumping proppant slugs in orderto create a hydraulic fracture including a network of proppant clusters,pillars, columns or islands and flow pathways, or a network of proppantrich regions including clusters, pillars, columns or islands andproppant lean regions rich, where the flow pathways separate theproppant clusters, pillars, columns or islands and the proppant leanregions separate the proppant rich regions. Interconnected pathways orproppant lean regions within the proppant pack form a network ofchannels throughout the fractures from its tip to the wellbore. Thenetwork of channels results in a significant increase of the effectivehydraulic conductivity of the created hydraulic fractures. Carrier fluidcomposition, proppant fluid composition, sequence of slugs, slugproperties, perforation pattern, and/or other fracturing operationparameters may be varied to increase, optimize, or maximize hydraulicfracture conductivity, where the perforation pattern acts as a“slug-splitter” as described above.

It should be noted that although some embodiments are described for thecase in which the fracturing layer is a single rock layer, it is notlimited to use in single layers. The fracturing layer may be a singlepay zone made up of multiple permeable layers. The fracturing layer mayalso be made up of more than one pay zone separated by one or moreimpermeable or nearly impermeable rock layers such as shale layers, andeach pay zone and each shale layer may in turn be made of multiple rocklayers. In one embodiment, each pay zone contains multiple perforationclusters and the processes of the invention occur in more than one payzone in a single treatment. In other embodiments, at least one of thepay zones is treated by the method and at least one of the pay zones istreated conventionally, in a single fracturing treatment. The result ismore than one fracture, at least one of which contains proppant placedheterogeneously according to the method of the invention. In anotherembodiment, the fracturing layer is made up of more than one pay zoneseparated by one or more impermeable or nearly impermeable rock layerssuch as shale layers, and each pay zone and each shale layer may in turnbe made of multiple rock layers, and at least one pay zone containsmultiple perforation clusters and the processes of the invention occurin at least one pay zone in a single treatment, but the job is designedso that a single fracture is formed in all the pay zones and in anyintervening impermeable zones. Of course, any embodiment may beimplemented more than once in one well.

Simulations conducted have shown that the number of perforation clustersrequired for a given formation typically may vary from 1 to 100, but maybe as high as 300 for some the formations. Suitable sizes of pillarsdepends upon a number of factors, such as the “slug surface volume” (theproduct of the slurry flow rate and the slug duration), the number ofclusters, the leak-off rate into the formation, etc. Calculations haverevealed the importance of slug duration on the overall productivity ofthe heterogeneous fracture produced. Many reservoirs may require theslug duration to span a range of, for example, 2 to 60 sec (thiscorresponds to a slug surface volume of about 80 to 16,000 liters (0.5to 100 barrels (bbl)) given a range of flow rates for a typicalfracturing job of from 3,200 to 16,000 liters/minute (20 to 100 barrelsper minute (bpm)). Other reservoirs will require proppant slug durations(as measured in the surface equipment) to be up to, for example, 5 min(16,000 to 79,500 liters (100 to 500 bbl) of frac fluid given a flowrate of 3,200 to 16,000 liters/minute (20-100 bpm)). And finally, forthose treatments in which part of the fracture should be covered withproppant homogeneously, slugs may last for 10-20 minutes and longer.Furthermore, slug duration may also vary throughout the treatment inorder to vary characteristic pillar footprints within a single hydraulicfracture. Typical ranges of slug duration will be the same as justdetailed above. For example, a pumping schedule may start with 1 minlong slugs and finish pumping with 5 sec long proppant slugs with 5 secno-proppant intervals between them.

Compositions

The invention broadly relates to a composition including an amine and aphosphate ester. The composition modifies surfaces of solid materials orportions thereof altering the chemical and/or physical properties of thesurfaces. The altered properties permit the surfaces to become selfattracting or to permit the surfaces to be attractive to material havingsimilar chemical and/or physical properties. In the case of particlesincluding metal oxide particles such as particles of silica, alumina,titania, magnesia, zirconia, other metal oxides or oxides including amixture of these metal oxides (natural or synthetic), the compositionforms a complete or partial coating on the surfaces of the particles.The coating can interact with the surface by chemical and/or physicalinteractions including, without limitation, chemical bonds, hydrogenbonds, electrostatic interactions, dipolar interactions,hyperpolarizability interactions, cohesion, adhesion, adherence,mechanical adhesion or any other chemical and/or physical interactionthat allows a coating to form on the particles. The coated particleshave a greater aggregation or agglomeration propensity than the uncoatedparticles. Thus, the particles before treatment may be free flowing,while after coating are not free flowing, but tend to clump, aggregateor agglomerate. In cases, where the composition is used to coat surfacesof a geological formation, a synthetic metal oxide structure and/ormetal-oxide containing particles, the particles will not only tend toaggregate together, the particles also will tend to cling to the coatedformation or structural surfaces.

Treated Structures and Substrates

The present invention also broadly relates to structures and substratestreated with a composition of this invention, where the structures andsubstrates include surfaces that are partially or completely coated witha composition of this invention. The structures or substrates can beceramic or metallic or fibrous. The structures or substrates can be spunsuch as a glass wool or steel wool or can be honeycombed like catalyticconverters or the like that include channels that force fluid to flowthrough tortured paths so that particles in the fluid are forced incontact with the substrate or structured surfaces. Such structures orsubstrates are ideally suited as particulate filters or sand controlmedia.

Methods for Treating Particulate Solids

The present invention broadly relates to methods for treating metaloxide-containing surfaces including the step of contacting the metaloxide-containing material with a composition of this invention. Thecomposition forms a partial and/or complete coating on the materialsurfaces altering the properties of the material and/or surfaces thereofso that the materials and/or surfaces thereof are capable to interactingwith similarly treated materials to form agglomerated and/or aggregatedstructures. The treating may be designed to partially or completely coatcontinuous metal oxide containing surfaces and/or the surfaces of metaloxide containing particles. If both are treated, then the particlescannot only self-aggregate, but the particles may also aggregate,agglomerate and/or cling to the coated continuous surfaces. Thecompositions may be used in fracturing fluids, frac pack applications,sand pack applications, sand control applications, or any other downholeapplication. Moreover, structures, screens or filters coated with thecompositions of this invention may be used to attract and remove finesthat have been modified with the compositions of this invention.

Method for Fracturing and/or Propping

The present invention broadly relates to methods for fracturing aformation including the step of pumping a fracturing fluid including acomposition of this invention into a producing formation at a pressuresufficient to fracture the formation. The composition modifies anaggregation potential and/or zeta-potential of formation particles andformation surfaces during fracturing so that the formation particlesaggregate and/or cling to the formation surfaces or each otherincreasing fracturing efficiency and increasing productivity of thefracture formation. The composition of this invention can also be usedin a pre-pad step to modify the surfaces of the formation so that duringfracturing the formation surfaces are pre-coated. The prepared stepinvolves pumping a fluid into the formation ahead of the treatment toinitiate the fracture and to expose the formation face with fluidsdesigned to protect the formation. Beside just using the composition aspart of the fracturing fluid, the fracturing fluid can also includeparticles that have been prior treated with the composition of thisinvention, where the treated particles act as proppants to prop open theformation after fracturing. If the fracturing fluid also includes thecomposition, then the coated particle proppant will adhere to formationsurfaces to a greater degree than would uncoated particle proppant.

In an alternate embodiment of this invention, the fracturing fluidincludes particles coated with a composition of this invention asproppant. In this embodiment, the particles have a greaterself-aggregation propensity and will tend to aggregate in locations thatmay most need to be propped open. In all fracturing applicationsincluding proppants coated with or that become coated with thecomposition of this invention during fracturing, the coated proppantsare likely to have improved formation penetration and adherenceproperties. These greater penetration and adherence or adhesionproperties are due not only to a difference in the surface chemistry ofthe particles relative to the surface chemistry of un-treated particles,but also due to a deformability of the coating itself. Thus, theinventors believe that as the particles are being forced into theformation, the coating will deform to allow the particles to penetrateinto a position and as the pressure is removed the particles will tendto remain in place due to the coating interaction with the surface anddue to the relaxation of the deformed coating. In addition, theinventors believe that the altered aggregation propensity of theparticles will increase proppant particle density in regions of theformation most susceptible to proppant penetration resulting in anenhance degree of formation propping.

Slug Sequencing and Heterogeneous Proppant Placement

Various software tools are commercially available for fracture modelingtool, either as licensable modules or as part of an overall fracturingsystem, such as, for example, the hydraulic fracturing design andevaluation engineering application available from Schlumberger OilfieldServices under the trade designation FRACCADE, which is available in anintegrated suite of engineering applications for well construction,production and intervention available under the trade designation CADEOFFICE. For example, the FRACCADE modeling tool is available with: aclosure test/calibration module under the trade designation DATAFRAC; aPSG module; an APM module; an optimization sub-module; a P3D simulator;an acid fracturing simulator; a multi-layered fracture sub-module; andso on; that can be used in an heterogeneous proppant placement (HPP) jobor can be appropriately modified by the skilled artisan for use in anHPP job. For example, the PSG module may be modified with a dispersionalgorithm to produce a pulsated proppant pumping schedule.

The design and updating of the model can include determining the amountof proppant for delivery. For example, an initial model can solve anoptimization problem to determine the amount of proppant to be used toachieve particular fracture dimension. Results from the solved problemcan then be used to develop an initial proppant placement schedule. Asused herein, the term “proppant placement schedule” refers to a schedulefor placing the proppant in the fracture and can include a pumpingschedule, a perforation strategy, and the like or a combination thereof.A pumping schedule is a plan prepared to specify the sequence, type,content and volume of fluids to be pumped during a specific treatment. Aperforation strategy is a plan to direct the flow of a well treatmentfluid through certain perforations in a wellbore casing and/or toinhibit flow through other perforations and can include, for example,plugging and/or opening existing perforations or making new perforationsto enhance conductivity and to control fracture growth.

The proppant placement schedule can include varying a proppantconcentration profile in the treatment fluid. Further, the proppantconcentration profile can be varied according to a dispersion method.For example, the model can include process control algorithms which canbe implemented to vary surface proppant concentration profile to delivera particular proppant slug concentration profile at perforationintervals. Under a normal pumping process, a slug of proppant injectedinto a wellbore will undergo dispersion and stretch and loose“sharpness” of the proppant concentration at the leading and tail edgesof the proppant slug. For a uniform proppant concentration profile, thesurface concentration profile can be solved by inverting a solution to aslug dispersion problem. Dispersion can thus be a mechanism which“corrects” the slug concentration profile from an initial surface valueto a particular downhole profile.

With reference to E. L. Cussler, Diffusion: Mass Transfer in FluidSystems, Cambridge University Press, pp. 89-93 (1984), an example of asystem of equations that can be solved is shown below for a Taylordispersion problem—laminar flow of a Newtonian fluid in a tube, where asolution is dilute, and mass transport is by radial diffusion and axialconvection only. Virtually any fluid mechanics problem can besubstituted for the above system, including turbulent or laminar flow,Newtonian or non-Newtonian fluids and fluids with or without particles.In practice, a downhole concentration profile will be defined, andequations solved in the inverse manner to determine initial conditions,for example, rates of addition for proppant, to achieve particulardownhole slug properties.

The equations can include, for example,

${\overset{\_}{c}}_{1} = {\frac{\frac{M}{\pi\; R_{0}^{2}}}{\sqrt{4\pi\; E_{z}t}}{\mathbb{e}}^{{{- {({z - {v^{0}t}})}^{2}}/4}E_{z}t}}$where M is total solute in a pulse (the material whose concentration isto be defined at a specific downhole location), R₀ is the radius of atube through which a slug is traveling, z is the distance along thetube, v⁰ is the fluid's velocity, and t is time. A dispersioncoefficient Ez can be shown to be,

$E = \frac{\left( {R_{0}v^{0}} \right)^{2}}{48D}$where D is a diffusion coefficient. A system of equations that yieldthis solution follows. Variable definitions can be found in E. L.Cussler, Diffusion: Mass Transfer in Fluid Systems, Cambridge UniversityPress, pp. 89-93 (1984).

$\frac{\partial{\overset{\_}{c}}_{1}}{\partial\tau} = {\left( \frac{v^{0}R_{0}}{48D} \right)\frac{\partial^{2}{\overset{\_}{c}}_{1}}{\partial\zeta^{2}}}$subject to the conditions,

${\tau = 0},{{all}\mspace{14mu}\zeta},{{\overset{\_}{c}}_{1} = {\frac{M}{\pi\; R_{0}^{2}}{\delta(\zeta)}}}$${\tau > 0},{\zeta = {\pm \infty}},{{\overset{\_}{c}}_{1} = 0}$${\tau > 0},{\zeta = 0},\frac{\delta{\overset{\_}{c}}_{1}}{\delta\tau}$

The system of equations above can be applied in general to design anydownhole proppant concentration profile, slugged or continuous. Thesolution for a dispersion of granular material flow in a fluid down awellbore can be inverted to calculate a corresponding surfaceconcentration of proppant in the fracturing fluid. Process controltechnology can then take this surface concentration schedule andproportion the proppant accordingly. For example, the surfaceconcentration schedule can be factored into the model, the proppantplacement schedule adjusted to the model and proppant deliveredaccording to the proppant placement schedule.

The pumping time of “no slug”, for example when the proppant-lean fluidis pumped, is one of the key parameters in an HPP proppant placementschedule. The “no slug” parameter can control the distance betweencolumns of pillars created in the fracture. A “no slug” time which istoo high can result in a pinching point, an area in which the fractureis at least partially collapsed due to a lack of support between twocolumns of pillars. A pinch point, or pinching, can block fractureconductivity and, therefore, effect production.

Another example of a computer software suite for performingheterogeneous proppant placement is found in U.S. Pat. No. 7,451,812issued 18 Nov. 2008, but any protocol of slug injection, slugsequencing, and slug alternation may be used to produce and/or improveproppant island placement.

In a first order approximation the distance, L, between two neighboringcolumns of pillars in the fracture can be calculated by the followingdependence relation:

$L = \frac{t_{noslug} \cdot Q_{rate}}{2 \cdot w_{frac} \cdot H_{frac}}$where t_(noslug) is the pumping time during which no proppant is pumped,Q_(rate) is the pump flowrate, w_(frac) is the fracture width andH_(frac) is the fracture height. The numerator thus includes the totalvolume of the no-proppant slug. In the denominator, a factor of 2accounts for two fracture wings.

Pinching can occur whenever the distance L is smaller than a criticalvalue, L_(crit), wherein:

$L = \frac{t_{noslug} \cdot Q_{rate}}{2 \cdot w_{frac} \cdot H_{frac}}$

The two parameters in the numerator on the right side of the aboveequation can be controlled during treatment, while the two in thedenominator are not controlled and can change during treatment.

The consequences of pinching can be dramatic. Overall fractureconductivity can be considered as a chain of hydraulic conductivities ofdifferent parts of the fracture. Thus, the overall conductivity can begoverned by the conductivity of a less-conducted fracture part. In thecase of pinching, the fracture conductivity can be equal to theconductivity of the area where pinching occurred.

A simplified equation can be used to calculate fracture conductivity.The fracture conductivity is proportional to the third power of fracturewidthk˜w³where k is the fracture conductivity and w is the fracture width.

In a pinching area, fracture width can be of the order of 0.05 mm orless, with this width due to the natural roughness of the fracturewalls. In extreme cases where there is little to no wall roughness, thefracture width is essentially equal to zero (0), as is the effectivefracture conductivity.

The mechanical properties of the pillars expected to form and of theformation such as, for example, Young's modulus, Poisson's ratio,formation effective stress, and the like can have a large impact on thefracture modeling and treatment design. For example, an optimizationproblem according to the formation mechanical properties can be solvedduring the design of an initial model to maximize the open channelvolume within a fracture.

Young's modulus refers to an elastic constant which is the ratio oflongitudinal stress to longitudinal strain and is symbolized by E. Itcan be expressed mathematically as follows: E=(F/A)/(ΔL/L), whereE=Young's modulus, F=force, A=area, ΔL=change in length, and L=originalarea.

Poisson's ratio is an elastic constant which is a measure of thecompressibility of material perpendicular to applied stress, or theratio of latitudinal to longitudinal strain. Poisson's ratio can beexpressed in terms of properties that can be measured in the field,including velocities of P-waves and S-waves as follows:σ=½(V_(p2)−2V_(s) ²)/(V_(p2)−V_(s) ²), where σ=Poisson's ratio,V_(p)=P-wave velocity and V_(s)=S-wave velocity. Effective stress, alsoknow as “effective pressure” or “intergranular pressure”, refers to theaverage normal force per unit area transmitted directly from particle toparticle of a rock or soil mass.

Scheduling and placement of the proppant during the HPP hydraulicfracture treatment can be different than traditional treatments. In HPPtreatments, slugging the proppant can aid in correctly placing clustersin various locations in the fracture. For example, the proppantplacement schedule can include slugs of proppant alternated with aproppant-lean fluid, for example “no slug” fluids, as illustrated in theHPP examples of FIGS. 1A-D wherein the alternating proppant slug andproppant-lean fluid technique is compared with the techniques ofcontinuously increasing proppant injection and step change proppantinjection, respectively. Proppant-lean fluids can include fluids withsome concentration of proppant, though the concentration of proppant inthe proppant-lean fluid is less than the concentration of proppant inthe proppant slug.

Heterogeneous proppant placement for open channels in a proppant packcan be achieved by applying techniques such as addition of aheterogeneity trigger to the treatment fluid while pumping. Thetreatment fluid can include a chemical reactant heterogeneity trigger, aphysical heterogeneity trigger such as fibers or a combination thereof.In some treatments, a trigger may be added periodically.

Embodiments of the present invention relate to re-healable proppantislands that comprise a first amount of a treated proppant, where thetreated proppant comprises a proppant having a partial or completecoating of a zeta potential altering composition. The first amount issufficient: (a) to allow formation of proppant islands in fracturesformed in a formation or zone thereof during fracturing operations andto maintain the proppant islands substantially intact, if the proppantislands and/or particles within the proppant islands move within theformation during and/or after fracturing operations, or during injectionoperations, or during production operations, or (b) to allow formationof proppant islands in fractures formed in a formation or zone thereofduring fracturing operations, to allow the proppant islands to re-healor break apart and reform during and/or after fracturing operations, orduring injection operations, or during production operations maintaininghigh fracture conductivity, and to capture formation fines during and/orafter fracturing operations, or during injection operations, or duringproduction operations. In other embodiments, the islands may furtherinclude a second amount untreated proppant, a third amount of anon-erodiblel fiber, and a fourth amount of an erodible materialcomprising erodible particles, erodible fibers, or mixtures andcombinations thereof. In other embodiments, the zeta potential alteringcomposition comprises an aggregating composition comprising anamine-phosphate reaction product, an amine component, an amine-phosphatereaction product, amine polymeric aggregating composition, a coacervateaggregating composition, or mixtures and combinations thereof.

Embodiments of this invention relate to self healing proppant islandsthat comprise a first amount of a treated proppant, where the treatedproppant comprises a proppant having a partial or complete coating of anaggregating composition comprising an amine-phosphate reaction product,amine component and amine-phosphate reaction product, amine polymericaggregating composition, a coacervate aggregating composition, ormixtures and combinations thereof, where the second amount issufficient: (a) to allow formation of proppant islands in fracturesformed in a formation or zone thereof and to allow the islands to breakapart and reform without substantial loss in proppant during and/orafter fracturing operations, or during injection operations, or duringproduction operations, or (b) to allow formation of proppant islands infractures formed in a formation or zone thereof, to allow the islands tobreak apart and reform without substantial loss in proppant duringand/or after fracturing operations, or during injection operations, orduring production operations, and to capture formation fines duringand/or after fracturing operations, or during injection operations, orduring production operations. In certain embodiments, the islandsfurther comprise a second amount untreated proppant, a third amount of anon-erodible fiber, and a fourth amount of an erodible materialcomprising erodible particles, erodible fibers, or mixtures andcombinations thereof, where the relative amounts of the different typeof proppant materials and fibers are chosen to fit particular featuresof a formation to be fractured. In other embodiments, the zeta potentialaltering composition comprises an aggregating composition comprising anamine-phosphate reaction product, an amine component, an amine-phosphatereaction product, amine polymeric aggregating composition, a coacervateaggregating composition, or mixtures and combinations thereof.

Embodiments of this invention relate to compositions for formingproppants islands within a formation or zone thereof, where thecomposition comprises a first amount of a treated proppant, where thetreated proppant comprises a proppant having a partial or completecoating of a zeta potential altering composition, and the first amountis sufficient: (a) to allow the compositions to form islands in theformation or zone thereof during and/or after fracturing operations, or(b) to allow the compositions to form islands in the formation or zonethereof and to capture formation fines during and/or after fracturingoperations, or during injection operations, or during productionoperations. In certain embodiments, the islands further comprise asecond amount untreated proppant, a third amount of a non-erodiblefiber, and a fourth amount of an erodible material comprising erodibleparticles, erodible fibers, or mixtures and combinations thereof. Inother embodiments, the zeta potential altering composition comprises anaggregating composition comprising an amine-phosphate reaction product,an amine component, an amine-phosphate reaction product, amine polymericaggregating composition, a coacervate aggregating composition, ormixtures and combinations thereof.

Embodiments of this invention relate to systems for forming proppantpillars in a formation during formation fracturing comprising the stepsof a sequence of injections of a plurality of different fracturingfluids, where the different fracturing fluids selected from the groupsconsisting of: (a) proppant-free fluids including (i) a base fluid or(ii) a base fluid and an aggregating composition and/or a viscosifyingcomposition and (b) proppant-containing fluids including (i) a basefluid, a viscosifying composition, and a proppant composition or (ii) abase fluid, a viscosifying composition, a proppant composition and anaggregating composition. In certain embodiments, the sequences mayinclude single injections of each fluid in any order or multipleinjections of each fluid in any order. In other embodiments, thesequence may include a plurality of first fluid injections, a pluralityof second fluid injections, and a plurality of third fluid injections.In other embodiments, the sequence may include single injections of thefirst, second, and third fluids repeated a number of times, where thenumber of times extends over the entire proppant placement stage of thefracturing operation. In other embodiments, the sequence may includemultiple injections of each fluid in any given order. In otherembodiments, the sequence may also include a hold period between eachinjection. In other embodiments, the sequence may include a first fluidinjection, a first hold time, a second fluid injection, a second holdtime, and a third fluid injection, and a third hold time, where thefirst, second and third fluid may be any of the fluid compositionslisted above.

Embodiments of this invention relate to methods for fracturing includinga pad stage comprising injecting into a formation a pad fluid into aformation under fracturing conditions to fracture and/or extendfractures. The methods also include a proppant placement stagecomprising injecting a series of proppant stages fluids according to asequence designed to form proppant pillars or islands in the fractures.The proppant stage fluids include at least one proppant-free fluid andat least one proppant-containing fluid. The proppant-free fluids includeviscosified fluids with or without an aggregating composition andcrosslinked viscosified fluids with or without an aggregatingcomposition. The proppant-containing fluids include viscosified fluidsincluding a proppant compositions with or without an aggregatingcomposition, a crosslinked fluid including a proppant composition withor without an aggregating composition. The methods may also include atail-in stage comprising injecting in a tail-in fluid. The proppantstage may include the sequential injection of thousands of slugs ofproppant-free and proppant-containing fluids, where the slug pulses havea duration between 5 s and 30 s.

Embodiments of this invention relate to methods for fracturing asubterranean formation comprising a proppant placement stage comprisinginjecting into the formation penetrated by a wellbore at least twofracturing fluids differing in: (1) at least one proppant compositionproperty, or (2) at least one fracturing fluid property, or (3) acombination of these differences, where the differences improve proppantplacement and proppant island formation in the fractures. In certainembodiments, the fracturing fluid properties include fluid composition,fluid pressure, fluid temperature, fluid pulse duration, proppantsettling rate, or mixtures and combinations thereof, and the proppantcomposition properties include proppant types, proppant sizes, proppantstrengths, proppant shapes, or mixtures and combinations thereof. Inother embodiments, the fracturing fluids are selected from the groupconsisting of (a) proppant-free fluids including (i) a base fluid or(ii) a base fluid and an aggregating composition and/or a viscosifyingcomposition and (b) proppant-containing fluids including (i) a basefluid, a viscosifying composition, and a proppant composition or (ii) abase fluid, a viscosifying composition, a proppant composition and anaggregating composition. In other embodiments, the aggregatingcomposition comprising an amine-phosphate reaction product, aminecomponent, amine polymeric aggregating composition, a coacervateaggregating composition, or mixtures and combinations thereof. In otherembodiments, the proppant composition including untreated proppant,treated proppant, or mixtures and combinations thereof. In otherembodiments, the treated proppant comprises a proppant having a partialor complete coating of an aggregating composition comprising anamine-phosphate reaction product, amine component, amine polymericaggregating composition, a coacervate aggregating composition, ormixtures and combinations thereof. In other embodiments, the proppantcompositions differ in at least one of the following properties: (a) anamounts of untreated and treated proppant, (b) densities of theuntreated and/or treated proppants, (c) sizes of the untreated and/ortreated proppants, (d) shapes of the untreated and/or treated proppants,or (e) strengths of the untreated and/or treated proppants. In otherembodiments, the proppant compositions further include (i) anon-erodiblefiber, (ii) an erodible material comprising erodible particles, erodiblefibers, or mixtures and combinations thereof, or (iii) mixtures orcombinations thereof. In other embodiments, the proppant settling rateis control by adjusting a pumping rates. In other embodiments, theviscosified fracturing fluids differ in the viscosifying composition. Inother embodiments, the injecting step comprises injecting the at leasttwo different fracturing fluids according to an injection sequence. Atleast one of the fluids is proppant-free and at least one of the fluidsincludes a proppant composition. In other embodiments, the injectionsequence comprises injecting the at least two different fracturingfluids in alternating stages during the fracturing operation. In otherembodiments, the methods further comprises prior to the proppantplacement step, a pad stage comprising injecting into the a pad fluidcomprising a base fluid and a viscosifying composition or a base fluid,a viscosifying composition, and an aggregating composition.

Embodiments of this invention relate to methods for fracturing asubterranean formation comprising a proppant placement stage comprisinginjecting into the formation penetrated by a wellbore at least twodifferent fracturing fluid according to an injection sequence, where thefracturing fluids differ in at least one property. In certainembodiments, the methods further comprises prior to the proppantplacement step, a pad stage comprising injecting into the a pad fluidcomprising a base fluid and a viscosifying composition or a base fluid,a viscosifying composition, and an aggregating composition. In certainembodiments, the properties include a fluid composition, a fluidpressure, a fluid temperature, a fluid pulse duration, a proppantsettling rate, proppant types, proppant sizes, proppant strengths,proppant shapes, or mixtures and combinations thereof. In certainembodiments, the fracturing fluids are selected from the groupconsisting of (a) proppant-free fluids including (i) a base fluid or(ii) a base fluid and an aggregating composition and/or a viscosifyingcomposition and (b) proppant-containing fluids including (i) a basefluid, a viscosifying composition, and a proppant composition or (ii) abase fluid, a viscosifying composition, a proppant composition and anaggregating composition. In other embodiments, the aggregatingcomposition comprising an amine-phosphate reaction product, aminecomponent, amine polymeric aggregating composition, a coacervateaggregating composition, or mixtures and combinations thereof. In otherembodiments, the proppant composition including untreated proppant,treated proppant, or mixtures and combinations thereof. In otherembodiments, the treated proppant comprises a proppant having a partialor complete coating of an aggregating composition comprising anamine-phosphate reaction product, amine component, amine polymericaggregating composition, a coacervate aggregating composition, ormixtures and combinations thereof. In other embodiments, the proppantcompositions differ in at least one of the following properties: (a) anamounts of untreated and treated proppant, (b) densities of theuntreated and/or treated proppants, (c) sizes of the untreated and/ortreated proppants, (d) shapes of the untreated and/or treated proppants,or (e) strengths of the untreated and/or treated proppants. In otherembodiments, the proppant compositions further include (i) anon-erodible fiber, (ii) an erodible material comprising erodibleparticles, erodible fibers, or mixtures and combinations thereof, or(iii) mixtures or combinations thereof. In other embodiments, theproppant settling rate is control by adjusting a pumping rates. In otherembodiments, the viscosified fracturing fluids differ in theviscosifying composition. In other embodiments, the injecting stepcomprises injecting the at least two different fracturing fluidsaccording to an injection sequence. In other embodiments, at least oneof the fluids is proppant-free and at least one of the fluids includes aproppant composition. In other embodiments, the injection sequencecomprises injecting the at least two different fracturing fluids inalternating stages during the fracturing operation. In otherembodiments, the methods further comprising after the proppant placementstep, a tail-in stage comprising injecting into the a tail-in fluidcomprising (i) a base fluid, a viscosifying composition, and aproppantcomposition or (ii) abase fluid, a viscosifying composition, aproppantcomposition, and an aggregating composition.

Embodiments of this invention relate to methods for placing aproppant/flow path network in fractures in a fracturing layer penetratedby a wellbore, the method comprises a proppant placement stagecomprising injecting, into the fracturing layer above fracturingpressure through a pattern of perforations comprising groups ofperforations separated by non-perforated spans, a sequence of slugs ofat least one proppant-free fluid selected from the group consisting of anon-viscosified proppant-free fluid or a viscosified proppant-free fluidand at least one proppant-containing fluid selected from the groupconsisting of a non-viscosified proppant-containing fluid or aviscosified proppant-containing fluid. In certain embodiments, thenon-viscosified proppant-free fluid comprises (a) a base fluid or (b) abase fluid and an aggregating composition. In other embodiments, theviscosified proppant-free fluid comprises (a) a base fluid and aviscosifying composition or (b) a base fluid, a viscosifyingcomposition, and an aggregating composition. In other embodiments, thenon-viscosified proppant-containing comprises (a) a base fluid and aproppant composition, or (b) a base fluid, a proppant composition, andan aggregating composition. In other embodiments, the viscosifiedproppant-containing comprises (a) a base fluid, a viscosifyingcomposition and, a proppant composition or (b) a base fluid, aviscosifying composition, a proppant composition, and an aggregatingcomposition. In other embodiments, the aggregating composition comprisesan amine-phosphate reaction product, amine component, amine polymericaggregating composition, a coacervate aggregating composition, ormixtures and combinations thereof. In other embodiments, theproppant-containing fluids form proppant pillars within the fracturesduring fracturing and/or after fracturing as the fractures closes. Inother embodiments, the methods further comprises causing the sequence ofslugs injected through neighboring perforation groups to move throughthe fractures at different rates. In other embodiments, at least one ofthe parameters slug volume, slug composition, proppant composition,proppant sizes, proppant shapes, proppant densities, proppant strengths,proppant concentrations, pattern length, number of perforation groups,perforation group separations, perforation group orientations, number ofholes in each perforation group, perforation group shot densities,perforation group lengths, number of non-perforation spans,non-perforation span lengths, methods of perforation, or combinationsthereof change according to the slug sequence. In other embodiments, theproppant composition comprises a first amount of an untreated proppant,a second amount of a treated proppant, a third amount of an erodible ordissolvable proppant, and a fourth amount of a non-erodible fiber. Inother embodiments, the treated proppant comprises a proppant having apartial or complete coating of the aggregating composition. In otherembodiments, the erodible or dissolvable proppant comprises erodible ordissolvable organic particles, erodible or dissolvable organic fibers,erodible or dissolvable inorganic particles, and/or erodible ordissolvable inorganic fibers. In other embodiments, the non-erodiblefibers comprise non-erodible organic fibers and/or non-erodibleinorganic fibers. In other embodiments, a sum of the second amount is100 wt. %, the first, third and fourth amounts may range between 0 wt. %and 100 wt. %, and the amounts may sum to values greater than 100%. Inother embodiments, the methods further comprises prior to the proppantplacement step, a pad stage comprising continuously injecting aviscosified proppant-free fluid into the fracturing fluid underfracturing conditions to form or elongate fractures. In otherembodiments, the methods further comprises after the proppant placementstep, a tail-in-stage comprising continuously injecting a viscosifiedproppant-containing fluid into the fracturing fluid.

Embodiments of this invention relate to methods for heterogeneousproppant placement in a fracture in a fracturing layer, the methodcomprising a) a proppant placement stage comprising injecting, into thefracturing layer above fracturing pressure through a pattern ofperforations comprising groups of perforations separated bynon-perforated spans, a sequence of slugs of at least one proppant-freefluid selected from the group consisting of a non-viscosifiedproppant-free fluid or a viscosified proppant-free fluid and at leastone proppant-containing fluid selected from the group consisting of anon-viscosified proppant-containing fluid or a viscosifiedproppant-containing fluid, and b) causing the sequence of slugs injectedthrough neighboring perforation groups to move through the fractures atdifferent rates. In certain embodiments, the non-viscosifiedproppant-free fluid comprises (a) a base fluid or (b) a base fluid andan aggregating composition. In other embodiments, the viscosifiedproppant-free fluid comprises (a) a base fluid and a viscosifyingcomposition or (b) a base fluid, a viscosifying composition, and anaggregating composition. In other embodiments, the non-viscosifiedproppant-containing comprises (a) a base fluid and a proppantcomposition, or (b) a base fluid, a proppant composition, and anaggregating composition. In other embodiments, the viscosifiedproppant-containing comprises (a) a base fluid, a viscosifyingcomposition and, a proppant composition or (b) a base fluid, aviscosifying composition, a proppant composition, and an aggregatingcomposition. In other embodiments, the aggregating composition comprisesan amine-phosphate reaction product, amine component, amine polymericaggregating composition, a coacervate aggregating composition, ormixtures and combinations thereof. In other embodiments, theproppant-containing fluids form proppant pillars within the fracturesduring fracturing and/or after fracturing as the fractures closes. Inother embodiments, the methods further comprises prior to the proppantplacement step, a pad stage comprising continuously injecting aviscosified proppant-free fluid into the fracturing fluid underfracturing conditions to form or elongate fractures. In otherembodiments, the methods further comprises after the proppant placementstep, a tail-in-stage comprising continuously injecting a viscosifiedproppant-containing fluid into the fracturing fluid. In otherembodiments, at least one of the parameters slug volume, slugcomposition, proppant composition, proppant sizes, proppant shapes,proppant densities, proppant strengths, proppant concentrations, patternlength, number of perforation groups, perforation group separation,perforation group orientations, number of holes in each perforationgroup, perforation group shot densities, perforation group lengths,number of non-perforation spans, non-perforation span lengths, methodsof perforation, or combinations thereof change according to the slugsequence. In other embodiments, a volume of the proppant-containingfluids is less than a volume of the proppant-free fluids. In otherembodiments, a number of holes in each of the perforation groups is thesame or different. In other embodiments, an orientations of all of theperforation groups are the same or different. In other embodiments, adiameter of holes in all of the perforation groups is the same ordifferent. In other embodiments, perforation group lengths of all theperforation groups are the same or different. In other embodiments, atleast two different perforation methods for forming the perforationgroups are used. In other embodiments, some of the groups are producedusing an underbalanced perforation technique and some of the groups areproduced using an overbalanced perforation technique. In otherembodiments, at least two perforation groups allow flow of a sequence ofslugs of the proppant-free fluid and the proppant-containing fluid areseparated by a perforation group having sufficiently small perforationsthat the proppant bridges and proppant-free fluids enter the formationtherethrough. In other embodiments, every pair of perforation groupsthat produce a sequence of slugs of the proppant-free fluids and theproppant-containing fluids are separated by a perforation group havingsufficiently small perforations that the proppant bridges andproppant-free fluid enters the formation therethrough. In otherembodiments, a number of perforation groups is between 2 and 300. Inother embodiments, the number of groups of perforations is between 2 and100. In other embodiments, the perforation group length is between 0.15m and 3.0 m. In other embodiments, the perforation group separation isfrom 0.30 m to 30 m. In other embodiments, the perforation shot densityis from 1 to 30 shots per 0.3 m. In other embodiments, a fluid injectiondesign is determined from a mathematical model. In other embodiments, aperforation pattern design is determined from a mathematical model. Inother embodiments, the proppant pillars are a proppant/flow pathwaynetwork in the fractures such that the pillars do not extend over anentire dimension of the fractures parallel to the wellbore but areinterrupted by flow paths that lead to the wellbore. In otherembodiments, the proppant slugs have a volume between 80 and 16,000liters. In other embodiments, the perforations are slots cut into tubinglining the wellbore.

Embodiments of this invention relate to compositions comprising asubterranean formation penetrated by a wellbore, where the formationincludes fractures having a proppant/flow pathway network, where thenetwork comprises a plurality of proppant clusters forming pillars and aplurality of flow pathways extending through the network to the wellboreimproving fluid flow into or out of the fractures. In certainembodiments, the proppant clusters comprises a first amount of untreatedproppant, a second amount of treated proppant, and a third amount ofnon-erodible fibers. In other embodiments, the treated proppantcomprises a proppant having a partial or complete coating of anaggregating composition comprising an amine-phosphate reaction product,amine component, amine polymeric aggregating composition, a coacervateaggregating composition, or mixtures and combinations thereof. In otherembodiments, the second amount is sufficient: (a) to form the network inthe fractures, (b) to maintain the clusters substantially in tact, ifthe clusters move or break up and reform within the fractures duringand/or after a fracturing operation, (c) to enable and enhance fluidflow into and out of the formation through the fractures, (d) to captureformation fines during and/or after a fracturing operation, or during ainjection operation, or during production operation, or (e) mixtures andcombinations thereof. In other embodiments, the network comprisesproppant-rich regions and proppant-lean regions, where the proppant-leanregions include no or less than 10% of clusters in the proppant-richregions. In other embodiments, the untreated proppant is selected fromthe group consisting of sand, nut hulls, ceramics, bauxites, glass,natural materials, plastic beads, particulate metals, drill cuttings,and combinations thereof. In other embodiments, the treated proppantcomprising the untreated proppant including a partial or completecoating of the aggregating composition. In other embodiments, the secondamount is 100 wt. %, the first and third amounts may range between 0 wt.% and 100 wt. %, and the amounts may sum to values greater than 100%. Inother embodiments, the proppant clusters further comprise a fifth amountof erodible or dissolvable proppant particles and/or fibers, theerodible or dissolvable proppant particles and/or fibers that form aplurality of erodible or dissolvable clusters within the network, whicherode or dissolve to from additional flow pathways in network. In otherembodiments, a sum of the second and third amounts is 100 wt. %, thefirst, fourth and fifth amounts may range between 0 wt. % and 100 wt. %,and the amounts may sum to values greater than 100%.

Embodiments of this invention relate to compositions comprising asubterranean formation penetrated by a wellbore, where the formationincludes fractures having a proppant/flow pathway network, where thenetwork comprises a plurality of proppant clusters forming pillars, aplurality of erodible or dissolvable clusters, and a plurality of flowpathways extending through the network to the wellbore improving fluidflow into or out of the fractures. In certain embodiments, the proppantclusters comprises proppant composition including a first amount ofuntreated proppant, a second amount of treated proppant, a third amountof erodible or dissolvable proppant particles and/or fibers, and afourth amount of non-erodible fibers. In other embodiments, the treatedproppant comprises a proppant having a partial or complete coating of anaggregating composition comprising an amine-phosphate reaction product,amine component and amine-phosphate reaction product, amine polymericaggregating composition, a coacervate aggregating composition, ormixtures and combinations thereof. In other embodiments, the secondamount is sufficient: (a) to form the clusters in the fracture, (b) tomaintain the clusters substantially in tact, if the mobile proppantisland moves within a formation during fracturing operations, (c) toenable and enhance fluid flow from the formation through the fracturetoward the wellbore, (d) to capture formation fines during fracturingoperations, injection operations, or production operations, or (e)mixtures and combinations thereof. In other embodiments, the networkcomprises proppant-rich regions and proppant-lean regions, where theproppant-lean regions include no or less than 10% of clusters in theproppant-rich regions. In other embodiments, the untreated proppant isselected from the group consisting of sand, nut hulls, ceramics,bauxites, glass, natural materials, plastic beads, particulate metals,drill cuttings, and combinations thereof. In other embodiments, thetreated proppant comprise the untreated proppant including a partial orcomplete coating of the aggregating composition. In other embodiments, asum of the second and third amounts is 100 wt. %, the first, fourth andfifth amounts may range between 0 wt. % and 100 wt. %, and the amountsmay sum to values greater than 100%.

Compositional Ranges Useful in the Invention

Fracturing fluids are all based on 100 wt. % of a base fluid and variouswt. % of the other components so that the final fracturing fluid weightpercentages may sum to greater than 100%, thus, the other componentsrepresent relative amounts. These formulations are therefore similar torubber compositions which are expressed relative amounts based on 100parts rubber. With this in mind, the fracturing fluids may include 100wt. % of a base fluid and varying amounts of: an aggregatingcomposition, a viscosifying composition, a proppant composition, andother additives. Base fluid are prepared from guar or guar derivatives,cellulose or cellulose derivatives, synthetic water soluble polymers,slick water polymer, surfactants etc. dissolved in brine, fresh water,produced water etc. as set forth herein. Table 1 tabulations permittedproppant-free fracturing fluid compositions in ranges of components.

TABLE 1 Proppant-Free Fluids-All Amount in Weight Percentages TypeBF^(a) AC^(b) VC^(d) OC^(e) PC^(f) 1 100 0 0 0 0 2 100 0.1-20 0 0 0(0.1-10) {0.1-5}  3 100 0 0 0 0 4 100 0 0.01-20 0 0 (0.01-10) {0.01-5} 5 100 0 0 0.01-20 0 (0.01-10) {0.01-5}  6 100 0.01-20 0 0 0 (0.01-10){0.01-5}  7 100 0.01-20 0.01-20 0 0 (0.01-10) (0.01-10) {0.01-5} {0.01-5}  8 100 0.01-20 0 0.01-20 0 (0.01-10) (0.01-10) {0.01-5} {0.01-5}  9 100 0 0.01-20 0 0 (0.01-10) {0.01-5} 10 100 0 0 0.01-20 0(0.01-10) {0.01-5}  11 100 0 0.01-20 0.01-20 0 12 100 0.01-20 0.01-20 00 (0.01-10) (0.01-10) {0.01-5}  {0.01-5}  13 100 0.01-20 0 0.01-20 0(0.01-10) (0.01-10) {0.01-5}  {0.01-5}  14 100 0.01-20 0.01-20 0.01-20 0(0.01-10) (0.01-10) (0.01-10) {0.01-5}  {0.01-5}  {0.01-5}  15 100 00.01-20 0.01-20 0 (0.01-10) (0.01-10) {0.01-5}  {0.01-5}  16 100 0.01-200.01-20 0.01-20 0 (0.01-10) (0.01-10) (0.01-10) {0.01-5}  {0.01-5} {0.01-5}  ^(a)base fluid, ^(b)aggregating composition, ^(c)coatingcrosslinking composition, ^(d)viscosifying composition, ^(e)otheradditives, and ^(f)proppant composition - ( ) narrower range, { } stillnarrower range, (( )) still narrower rangeTable 2 tabulates permitted proppant-containing fracturing fluids inranges of components.

TABLE 2 Proppant Containing Fluids-All Amount in Weight Percentages TypeBF^(a) AC^(b) VC^(d) OC^(e) PC^(f) 1 100 0 0 0 0.1-400 (0.1-300){0.1-200} ((.01-100)) 2 100 0.01-20 0 0 0.1-400 (0.01-10) (0.1-300){0.01-5}  {0.1-200} ((.01-100)) 3 100 0 0 0 0.1-400 (0.1-300) {0.1-200}((.01-100)) 4 100 0 0.01-20 0 0.1-400 (0.01-10) (0.1-300) {0.01-5} {0.1-200} ((.01-100)) 5 100 0 0 0.01-20 0.1-400 (0.01-10) (0.1-300){0.01-5}  {0.1-200} ((.01-100)) 6 100 0.01-20 0 0 0.1-400 (0.01-10)(0.1-300) {0.01-5}  {0.1-200} ((.01-100)) 7 100 0.01-20 0.01-20 00.1-400 (0.01-10) (0.01-10) (0.1-300) {0.01-5}  {0.01-5}  {0.1-200}((.01-100)) 8 100 0.01-20 0 0.01-20 0.1-400 (0.01-10) (0.01-10)(0.1-300) {0.01-5}  {0.01-5}  {0.1-200} ((.01-100)) 9 100 0 0.01-20 00.1-400 (0.01-10) (0.1-300) {0.01-5}  {0.1-200} ((.01-100)) 10 100 0 00.01-20 0.1-400 (0.01-10) (0.1-300) {0.01-5}  {0.1-200} ((.01-100)) 11100 0 0.01-20 0.01-20 0.1-400 (0.01-10) (0.01-10) (0.1-300) {0.01-5} {0.01-5}  {0.1-200} ((.01-100)) 12 100 0.01-20 0.01-20 0 0.1-400(0.01-10) (0.01-10) (0.1-300) {0.01-5}  {0.01-5}  {0.1-200} ((.01-100))13 100 0.01-20 0 0.01-20 0.1-400 (0.01-10) (0.01-10) (0.1-300) {0.01-5} {0.01-5}  {0.1-200} ((.01-100)) 14 100 0.01-20 0.01-20 0.01-20 0.1-400(0.01-10) (0.01-10) (0.01-10) (0.1-300) {0.01-5}  {0.01-5}  {0.01-5} {0.1-200} ((.01-100)) 15 100 0  0.1-20 0.1-20 0.1-400  (0.1-10) (0.1-10)(0.1-300) {0.1-5} {0.1-5} {0.1-200} ((.01-100)) 16 100 0.01-20 0.01-200.01-20 0.1-400 (0.01-10) (0.01-10) (0.01-10) (0.1-300) {0.01-5} {0.01-5}  {0.01-5}  {0.1-200} ((.01-100)) ^(a)base fluid,^(b)aggregating composition, ^(c)coating crosslinking composition,^(d)viscosifying composition, ^(e)other additives, and ^(f)proppantcomposition - ( ) narrower range, { } still narrower range, (( )) stillnarrower range

In certain embodiments, the viscosifying compositions include from about80 wt. % to about 99 wt. % of one viscosifying agent or a plurality ofviscosifying agents and from about 20 wt. % to about 0.1 wt. % of onecrosslinking agent or a plurality of crosslinking agents. A list ofviscosifying agents and crosslinking agents are set forth in theSuitable Reagents section herein.

In certain embodiments, the aggregating composition may comprise asingle aggregating agent or a plurality of aggregating agents in anyrelative mixture, where the agent and/or mixture selection may betailored to formation and proppant properties and characteristics.

In certain embodiments, the proppant composition of eachproppant-containing fracturing fluid may include from 0 wt. % to 100 wt.% of one untreated proppant or a plurality of untreated proppants andfrom 0 wt. % to 100 wt. % of one treated proppant or a plurality oftreated proppants, where the treated proppants comprise untreatedproppants treated with one aggregating agent or untreated proppantstreated with a plurality of the aggregating agents to form partial orcomplete aggregating coating on the proppants altering their aggregatingpropensity from low to maximal aggregating propensity according to theinformation shown in FIG. 6. It should be recognized that by changingthe amount of aggregating composition used or the extend of theaggregating coating on treated proppants, the relative or bulkaggregating propensity per the table of FIG. 6 may be altered to anydesired aggregating propensity to permit different proppant pillar orisland formation within fractures formed in a formation during formationfracturing.

Suitable Reagents for Use in this Invention

Base Fluids

The base fluids for use in this invention include, without limitation,any liquid base fluid suitable for use in oil and gas producing wells orinjections wells, or mixtures and combinations thereof. Exemplary liquidbase fluids include, without limitation, aqueous base fluids, organicbase fluids, water-in-oil base fluids, oil-in-water base fluids, anyother base fluids used in fracturing fluids, viscosified versionsthereof, or mixtures and combinations thereof. Exemplary aqueous basefluids include water, tap water, production water, salt water, brines,or mixtures and combinations thereof. Exemplary brines include, withoutlimitation, sodium chloride brines, potassium chloride brines, calciumchloride brines, magnesium chloride brines, tetramethyl ammoniumchloride brines, other chloride brines, phosphate brines, nitratebrines, other salt brines, or mixtures and combinations thereof.

Aqueous Base Fluids

Aqueous base fluids will generally comprise water, consist essentiallyof water, or consist of water. Water will typically be a major componentby weight 50 wt. % of the aqueous base fluids. The water may be potableor non-potable. The water may be brackish or contain other materialstypical of sources of water found in or near oil fields. For example, itis possible to use fresh water, brine, or even water to which any salt,such as an alkali metal or alkali earth metal salt (NaCO₃, NaCl, KCl,etc.) has been added. The aqueous fracturing fluids generally include atleast about 80 wt. % of an aqueous base fluid. In other embodiments, theaqueous fracturing fluids including 80 wt. %, 85 wt. %, 90 wt. %, and 95wt. % of an aqueous base fluid.

Organic Base Fluids

Organic base fluids comprise of a liquid organic carrier, consistessentially of a liquid organic carrier, or consist of a liquid organiccarrier or a hydrocarbon base fluid or a hydrocarbon base fluid includea hydrocarbon soluble polymer. The organic fracturing fluids generallyinclude at least about 80 wt. % of an organic base fluid. In otherembodiments, the aqueous fracturing fluids including 80 wt. %, 85 wt. %,90 wt. %, and 95 wt. % of an organic base fluid.

Hydrocarbon Base Fluids

Suitable hydrocarbon base fluids for use in this invention includes,without limitation, synthetic hydrocarbon fluids, petroleum basedhydrocarbon fluids, natural hydrocarbon (non-aqueous) fluids or othersimilar hydrocarbons or mixtures or combinations thereof. Thehydrocarbon fluids for use in the present invention have viscositiesranging from about 5×10⁻⁶ to about 600×10⁻⁶ m²/s (5 to about 600centistokes). Exemplary examples of such hydrocarbon fluids include,without limitation, polyalphaolefins, polybutenes, polyolesters,biodiesels, simple low molecular weight fatty esters of vegetable orvegetable oil fractions, simple esters of alcohols such as Exxate fromExxon Chemicals, vegetable oils, animal oils or esters, other essentialoil, diesel, diesel having a low or high sulfur content, kerosene,jet-fuel, white oils, mineral oils, mineral seal oils, hydrogenated oilsuch as PetroCanada HT-40N or IA-35 or similar oils produced by ShellOil Company, internal olefins (JO) having between about 12 and 20 carbonatoms, linear alpha olefins having between about 14 and 20 carbon atoms,polyalpha olefins having between about 12 and about 20 carbon atoms,isomerized alpha olefins (IAO) having between about 12 and about 20carbon atoms, VM&P Naptha, Linpar, Parafins having between 13 and about16 carbon atoms, and mixtures or combinations thereof.

Suitable polyalphaolefins (PAOs) include, without limitation,polyethylenes, polypropylenes, polybutenes, polypentenes, polyhexenes,polyheptenes, higher PAOs, copolymers thereof, and mixtures thereof.Exemplary examples of PAOs include PAOs sold by Mobil Chemical Companyas SHF fluids and PAOs sold formerly by Ethyl Corporation under the nameETHYLFLO and currently by Albemarle Corporation under the trade nameDurasyn. Such fluids include those specified as ETYHLFLO 162, 164, 166,168, 170, 174, and 180. Well suited PAOs for use in this inventioninclude bends of about 56% of ETHYLFLO now Durasyn 174 and about 44% ofETHYLFLO now Durasyn 168.

Exemplary examples of polybutenes include, without limitation, thosesold by Amoco Chemical Company and Exxon Chemical Company under thetrade names INDOPOL and PARAPOL, respectively. Well suited polybutenesfor use in this invention include Amoco's INDOPOL 100.

Exemplary examples of polyolester include, without limitation, neopentylglycols, trimethylolpropanes, pentaerythriols, dipentaerythritols, anddiesters such as dioctylsebacate (DOS), diactylazelate (DOZ), anddioctyladipate.

Exemplary examples of petroleum based fluids include, withoutlimitation, white mineral oils, paraffinic oils, andmedium-viscosity-index (MVI) naphthenic oils having viscosities rangingfrom about 5×10⁻⁶ to about 600×10⁻⁶ m²/s (5 to about 600 centistokes) at40° C. Exemplary examples of white mineral oils include those sold byWitco Corporation, Arco Chemical Company, PSI, and Penreco. Exemplaryexamples of paraffinic oils include solvent neutral oils available fromExxon Chemical Company, high-viscosity-index (HVI) neutral oilsavailable from Shell Chemical Company, and solvent treated neutral oilsavailable from Arco Chemical Company. Exemplary examples of MVInaphthenic oils include solvent extracted coastal pale oils availablefrom Exxon Chemical Company, MVI extracted/acid treated oils availablefrom Shell. Chemical Company, and naphthenic oils sold under the namesHydroCal and Calsol by Calumet and hydrogenated oils such as HT-40N andIA-35 from PetroCanada or Shell Oil Company or other similarhydrogenated oils.

Exemplary examples of vegetable oils include, without limitation, castoroils, corn oil, olive oil, sunflower oil, sesame oil, peanut oil, palmoil, palm kernel oil, coconut oil, butter fat, canola oil, rape seedoil, flax seed oil, cottonseed oil, linseed oil, other vegetable oils,modified vegetable oils such as crosslinked castor oils and the like,and mixtures thereof. Exemplary examples of animal oils include, withoutlimitation, tallow, mink oil, lard, other animal oils, and mixturesthereof. Other essential oils will work as well. Of course, mixtures ofall the above identified oils can be used as well.

Hydrocarbon Soluble Polymers

Suitable polymers for use as anti-settling additives or polymericsuspension agents in this invention include, without limitation, linearpolymers, block polymers, graft polymers, star polymers or othermulti-armed polymers, which include one or more olefin monomers and/orone or more diene monomers and mixtures or combinations thereof. Theterm polymer as used herein refers to homo-polymers, co-polymers,polymers including three of more monomers (olefin monomers and/or dienemonomers), polymer including oligomeric or polymeric grafts, which cancomprise the same or different monomer composition, arms extending forma polymeric center or starring reagent such as tri and tetra valentlinking agents or divinylbenzene nodes or the like, and homo-polymershaving differing tacticities or microstructures. Exemplary examples arestyrene-isoprene copolymers (random or block), triblocked,multi-blocked, styrene-butadiene copolymer (random or block),ethylene-propylene copolymer (random or block), sulphonated polystyrenepolymers, alkyl methacrylate polymers, vinyl pyrrolidone polymers, vinylpyridine, vinyl acetate, or mixtures or combinations thereof.

Suitable olefin monomer include, without limitation, any monounsaturatedcompound capable of being polymerized into a polymer or mixtures orcombinations thereof. Exemplary examples include ethylene, propylene,butylene, and other alpha olefins having between about 5 and about 20carbon atoms and sufficient hydrogens to satisfy the valencyrequirement, where one or more carbon atoms can be replaced by B, N, O,P, S, Ge or the like and one or more of the hydrogen atoms can bereplaced by F, Cl, Br, I, OR, SR, COOR, CHO, C(O)R, C(O)NH2, C(O)NHR,C(O)NRR′, or other similar monovalent groups, polymerizable internalmono-olefinic monomers or mixtures or combinations thereof, where R andR′ are the same or different and are carbyl group having between about 1to about 16 carbon atoms and where one or more of the carbon atoms andhydrogen atoms can be replaced as set forth immediately above.

Suitable diene monomer include, without limitation, any doublyunsaturated compound capable of being polymerized into a polymer ormixtures or combinations thereof. Exemplary examples include1,3-butadiene, isoprene, 2,3-dimethyl butadiene, or other polymerizablediene monomers.

The inventors have found that Infineum SV150, an isoprene-styrenedi-block and starred polymer, offers superior permanent shear stabilityand thickening efficiency due to its micelle forming nature.

Suitable hydrocarbon base fuels include, without limitation, t andmineral oil or diesel oil before adding organophillic clays, polaractivator, the additive to be suspended (Guar or Deriatized Guar, e.g.CMHPG) and the dispersing surfactant in concentrations between 0.10-5.0%w/w.

Viscoelastic Base Fluids

Viscoelastic base fluids comprise a liquid carrier includingviscoelastic surfactant (VAS) or a VAS gel.

The surfactant can generally be any surfactant. The surfactant ispreferably viscoelastic. The surfactant is preferably anionic. Theanionic surfactant can be an alkyl sarcosinate. The alkyl sarcosinatecan generally have any number of carbon atoms. Presently preferred alkylsarcosinates have about 12 to about 24 carbon atoms. The alkylsarcosinate can have about 14 to about 18 carbon atoms. Specificexamples of the number of carbon atoms include 12, 14, 16, 18, 20, 22,and 24 carbon atoms.

The anionic surfactant can have the chemical formula R₁CON(R₂)CH₂X,wherein R₁ is a hydrophobic chain having about 12 to about 24 carbonatoms, R₂ is hydrogen, methyl, ethyl, propyl, or butyl, and X iscarboxyl or sulfonyl. The hydrophobic chain can be an alkyl group, analkenyl group, an alkylarylalkyl group, or an alkoxyalkyl group.Specific examples of the hydrophobic chain include a tetradecyl group, ahexadecyl group, an octadecentyl group, an octadecyl group, and adocosenoic group.

The surfactant can generally be present in any weight percentconcentration. Presently preferred concentrations of surfactant areabout 0.1% to about 15% by weight. A presently more preferredconcentration is about 0.5% to about 6% by weight. Laboratory procedurescan be employed to determine the optimum concentrations for anyparticular situation.

The amphoteric polymer can generally be any amphoteric polymer. Theamphoteric polymer can be a nonionic water-soluble homopolysaccharide oran anionic water-soluble polysaccharide. The polymer can generally haveany molecular weight, and is presently preferred to have a molecularweight of at least about 500,000.

The polymer can be a hydrolyzed polyacrylamide polymer. The polymer canbe a scleroglucan, a modified scleroglucan, or a scleroglucan modifiedby contact with glyoxal or glutaraldehyde. The scleroglucans arenonionic water-soluble homopolysaccharides, or water-soluble anionicpolysaccharides, having molecular weights in excess of about 500,000,the molecules of which consist of a main straight chain formed ofD-glucose units which are bonded by β-1,3-bonds and one in three ofwhich is bonded to a side D-glucose unit by means of a β-1,6 bond. Thesepolysaccharides can be obtained by any of the known methods in the art,such as fermentation of a medium based on sugar and inorganic saltsunder the action of a microorganism of Sclerotium type A. A morecomplete description of such scleroglucans and their preparations may befound, for example, in U.S. Pat. Nos. 3,301,848 and 4,561,985,incorporated herein by reference. In aqueous solutions, the scleroglucanchains are combined in a triple helix, which explains the rigidity ofthe biopolymer, and consequently its features of highviscosity-increasing power and resistance to shearing stress.

It is possible to use, as source of scleroglucan, the scleroglucan whichis isolated from a fermentation medium, the product being in the form ofa powder or of a more or less concentrated solution in an aqueous and/oraqueous-alcoholic solvent. Scleroglucans customarily used inapplications in the petroleum field are also preferred according to thepresent invention, such as those which are white powders obtained byalcoholic precipitation of a fermentation broth in order to removeresidues of the producing organism (mycelium, for example).Additionally, it is possible to use the liquid reaction mixtureresulting from the fermentation and containing the scleroglucan insolution. According to the present invention, further suitablescleroglucans are the modified scleroglucan which result from thetreatment of scleroglucans with a dialdehyde reagent (glyoxal,glutaraldehyde, and the like), as well as those described in U.S. Pat.No. 6,162,449, incorporated herein by reference, (β-1,3-scleroglucanswith a cross-linked 3-dimensional structure produced by Sclerotiumrolfsii).

The polymer can be Aquatrol V (a synthetic compound which reduces waterproduction problems in well production; described in U.S. Pat. No.5,465,792, incorporated herein by reference), AquaCon (a moderatemolecular weight hydrophilic terpolymer based on polyacrylamide capableof binding to formation surfaces to enhance hydrocarbon production;described in U.S. Pat. No. 6,228,812, incorporated herein by reference)and Aquatrol C (an amphoteric polymeric material). Aquatrol V, AquatrolC, and AquaCon are commercially available from BJ Services Company.

The polymer can be a terpolymer synthesized from an anionic monomer, acationic monomer, and a neutral monomer. The monomers used preferablyhave similar reactivities so that the resultant amphoteric polymericmaterial has a random distribution of monomers. The anionic monomer cangenerally be any anionic monomer. Presently preferred anionic monomersinclude acrylic acid, methacrylic acid, 2-acrylamide-2-methylpropanesulfonic acid, and maleic anhydride. The cationic monomer can generallybe any cationic monomer. Presently preferred cationic monomers includedimethyl-diallyl ammonium chloride, dimethylamino-ethyl methacrylate,and allyltrimethyl ammonium chloride. The neutral monomer can generallybe any neutral monomer. Presently preferred neutral monomers includebutadiene, N-vinyl-2-pyrrolidone, methyl vinyl ether, methyl acrylate,maleic anhydride, styrene, vinyl acetate, acrylamide, methylmethacrylate, and acrylonitrile. The polymer can be a terpolymersynthesized from acrylic acid (AA), dimethyl diallyl ammonium chloride(DMDAC) or diallyl dimethyl ammonium chloride (DADMAC), and acrylamide(AM). The ratio of monomers in the terpolymer can generally be anyratio. A presently preferred ratio is about 1:1:1.

Another presently preferred amphoteric polymeric material (hereinafter“polymer 1”) includes approximately 30% polymerized AA, 40% polymerizedAM, and 10% polymerized DMDAC or DADMAC with approximately 20% freeresidual DMDAC or DADMAC which is not polymerized due to lower relativereactivity of the DMDAC or DADMAC monomer.

The fluid can further comprise one or more additives. The fluid canfurther comprise a base. The fluid can further comprise a salt. Thefluid can further comprise a buffer. The fluid can further comprise arelative permeability modifier. The fluid can further comprisemethylethylamine, monoethanolamine, triethylamine, triethanolamine,sodium hydroxide, potassium hydroxide, potassium carbonate, sodiumchloride, potassium chloride, potassium fluoride, KH₂PO₄, or K₂HPO₄. Thefluid can further comprise a proppant. Conventional proppants will befamiliar to those skilled in the art and include sand, resin coated sandsintered bauxite and similar materials. The proppant can be suspended inthe fluid.

Sarcosine (N-methylglycine) is a naturally occurring amino acid found instarfish, sea urchins and crustaceans. It can be purchased from avariety of commercial sources, or alternately produced by a number ofsynthetic routes known in the art including thermal decomposition ofcaffeine in the presence of barium hydroxide (Arch. Pharm. 232: 601,1894); (Bull. Chem. Soc. Japan, 39: 2535, 1966); and numerous others (T.Shirai in Synthetic Production and Utilization of Amino Acids; T.Kaneko, et al., Eds.; Wiley, New York: pp. 184-186, 1974). Sodiumsarcosinate is manufactured commercially from formaldehyde, sodiumcyanide and methyl amine (U.S. Pat. Nos. 2,720,540 and 3,009,954). Thepreferred sarcosinate are the condensation products of sodiumsarcosinate and a fatty acid chloride. The fatty acid chloride isreacted with sodium sarcosinate under carefully controlled alkalineconditions (i.e., the Schotten-Bauman reaction) to produce the fattysarcosinate sodium salt which is water soluble. Upon acidification, thefatty sarcosine acid, which is also water insoluble, is formed and maybe isolated from the reaction medium. The acyl sarcosines may beneutralized with bases such as the salts of sodium, potassium, ammonia,or organic bases such as triethanolamine in order to produce aqueoussolutions.

Another surfactant useful in the fluids of this invention are an anionicsarcosinate surfactant available commercially from BJ Services Companyas “M-Aquatrol” (MA). The MA-1 sarcosinate is a viscous liquidsurfactant with at least 94% oleoyl sarcosine. For hydraulic fracturing,a sufficient quantity of the sarcosinate is present in aqueous solutionto provide sufficient viscosity to suspend proppant during placement.The surfactant is preferably present at about 0.5% to about 10% byweight, most preferably at about 0.5% to about 6% by weight, based uponthe weight of the total fluid.

Viscosifying Agents

The hydratable polymer may be a water soluble polysaccharide, such asgalactomannan, cellulose, or derivatives thereof.

Suitable hydratable polymers that may be used in embodiments of theinvention include any of the hydratable polysaccharides which arecapable of forming a gel in the presence of a crosslinking agent. Forinstance, suitable hydratable polysaccharides include, but are notlimited to, galactomannan gums, glucomannan gums, guars, derived guars,and cellulose derivatives. Specific examples are guar gum, guar gumderivatives, locust bean gum, Karaya gum, carboxymethyl cellulose,carboxymethyl hydroxyethyl cellulose, and hydroxyethyl cellulose.Presently preferred gelling agents include, but are not limited to, guargums, hydroxypropyl guar, carboxymethyl hydroxypropyl guar,carboxymethyl guar, and carboxymethyl hydroxyethyl cellulose. Suitablehydratable polymers may also include synthetic polymers, such aspolyvinyl alcohol, polyacrylamides, poly-2-amino-2-methyl propanesulfonic acid, and various other synthetic polymers and copolymers.Other suitable polymers are known to those skilled in the art.

The hydratable polymer may be present in the fluid in concentrationsranging from about 0.10% to about 5.0% by weight of the aqueous fluid.In certain embodiments, the range for the hydratable polymer is about0.20% to about 0.80% by weight.

Viscosifying Agent Crosslinking Agents

The crosslinking agent may be a borate, titanate, orzirconium-containing compound. For example, the crosslinking agent canbe sodium borate×H₂O (varying waters of hydration), boric acid, boratecrosslinkers (a mixture of a titanate constituent, preferably anorganotitanate constituent, with a boron constituent. The organotitanateconstituent can be TYZORR titanium chelate esters from E.I du Pont deNemours & Company. The organotitanate constituent can be a mixture of afirst organotitanate compound having a lactate base and a secondorganotitanate compound having triethanolamine base. The boronconstituent can be selected from the group consisting of boric acid,sodium tetraborate, and mixtures thereof. These are described in U.S.Pat. No. 4,514,309, incorporated herein by reference, borate based oressuch as ulexite and colemanite, Ti(IV) acetylacetonate, Ti(IV)triethanolamine, Zr lactate, Zr triethanolamine, Zrlactate-triethanolamine, or Zrlactate-triethanolamine-triisopropanolamine. In some embodiments, thewell treatment fluid composition may further comprise a proppant.

A suitable crosslinking agent can be any compound that increases theviscosity of the fluid by chemical crosslinking, physical crosslinking,or any other mechanisms. For example, the gellation of a hydratablepolymer can be achieved by crosslinking the polymer with metal ionsincluding boron, zirconium, and titanium containing compounds, ormixtures thereof. One class of suitable crosslinking agents isorganotitanates. Another class of suitable crosslinking agents isborates as described, for example, in U.S. Pat. No. 4,514,309,incorporated herein by reference. The selection of an appropriatecrosslinking agent depends upon the type of treatment to be performedand the hydratable polymer to be used. The amount of the crosslinkingagent used also depends upon the well conditions and the type oftreatment to be effected, but is generally in the range of from about 10ppm to about 1000 ppm of metal ion of the crosslinking agent in thehydratable polymer fluid. In some applications, the aqueous polymersolution is crosslinked immediately upon addition of the crosslinkingagent to form a highly viscous gel. In other applications, the reactionof the crosslinking agent can be retarded so that viscous gel formationdoes not occur until the desired time.

In many instances, if not most, the viscosifying polymer is crosslinkedwith a suitable crosslinking agent. The crosslinked polymer has an evenhigher viscosity and is even more effective at carrying proppant intothe fractured formation. The borate ion has been used extensively as acrosslinking agent, typically in high pH fluids, for guar, guarderivatives and other galactomannans. See, for example, U.S. Pat. No.3,059,909, incorporated herein by reference and numerous other patentsthat describe this classic aqueous gel as a fracture fluid. Othercrosslinking agents include, for example, titanium crosslinkers (U.S.Pat. No. 3,888,312, incorporated herein by reference), chromium, iron,aluminum, and zirconium (U.S. Pat. No. 3,301,723, incorporated herein byreference). Of these, the titanium and zirconium crosslinking agents aretypically preferred. Examples of commonly used zirconium crosslinkingagents include zirconium triethanolamine complexes, zirconiumacetylacetonate, zirconium lactate, zirconium carbonate, and chelants oforganic alphahydroxycorboxylic acid and zirconium. Examples of commonlyused titanium crosslinking agents include titanium triethanolaminecomplexes, titanium acetylacetonate, titanium lactate, and chelants oforganic alphahydroxycorboxylic acid and titanium.

Similarly, the crosslinking agent(s) may be selected from those organicand inorganic compounds well known to those skilled in the art usefulfor such purpose, and the phrase “crosslinking agent”, as used herein,includes mixtures of such compounds. Exemplary organic crosslinkingagents include, but are not limited to, aldehydes, dialdehydes, phenols,substituted phenols, ethers, and mixtures thereof. Phenol, resorcinol,catechol, phloroglucinol, gallic acid, pyrogallol, 4,4′-diphenol,1,3-dihydroxynaphthalene, 1,4-benzoquinone, hydroquinone, quinhydrone,tannin, phenyl acetate, phenyl benzoate, 1-naphthyl acetate, 2-naphthylacetate, phenyl chloracetate, hydroxyphenylalkanols, formaldehyde,paraformaldehyde, acetaldehyde, prop analdehyde, butyraldehyde,isobutyraldehyde, valeraldehyde, heptaldehyde, decanal, glyoxal,glutaraldehyde, terephthaldehyde, hexamethyl-enetetramine, trioxane,tetraoxane, polyoxymethylene, and divinylether may be used. Typicalinorganic crosslinking agents are polyvalent metals, chelated polyvalentmetals, and compounds capable of yielding polyvalent metals, includingorganometallic compounds as well as borates and boron complexes, andmixtures thereof. In certain embodiments, the inorganic crosslinkingagents include chromium salts, complexes, or chelates, such as chromiumnitrate, chromium citrate, chromium acetate, chromium propionate,chromium malonate, chromium lactate, etc.; aluminum salts, such asaluminum citrate, aluminates, and aluminum complexes and chelates;titanium salts, complexes, and chelates; zirconium salts, complexes orchelates, such as zirconium lactate; and boron containing compounds suchas boric acid, borates, and boron complexes. Fluids containing additivessuch as those described in U.S. Pat. No. 4,683,068 and U.S. Pat. No.5,082,579 may be used.

As indicated, mixtures of polymeric gel forming material or gellants maybe used. Materials which may be used include water soluble crosslinkablepolymers, copolymers, and terpolymers, such as polyvinyl polymers,polyacrylamides, cellulose ethers, polysaccharides, lignosulfonates,ammonium salts thereof, alkali metal salts thereof, alkaline earth saltsof lignosulfonates, and mixtures thereof. Specific polymers are acrylicacid-acrylamide copolymers, acrylic acid-methacrylamide copolymers,polyacrylamides, partially hydrolyzed polyacrylamides, partiallyhydrolyzed polymethacrylamides, polyvinyl alcohol, polyvinyl acetate,polyalkyleneoxides, carboxycelluloses, carboxyalkylhydroxyethylcelluloses, hydroxyethylcellulose, galactomannans (e.g., guar gum),substituted galactomannans (e.g., hydroxypropyl guar),heteropolysaccharides obtained by the fermentation of starch-derivedsugar (e.g., xanthan gum), ammonium and alkali metal salts thereof, andmixtures thereof. In certain embodiments, the water solublecrosslinkable polymers include hydroxypropyl guar,carboxymethylhydroxypropyl guar, partially hydrolyzed polyacrylamides,xanthan gum, polyvinyl alcohol, the ammonium and alkali metal saltsthereof, and mixtures thereof.

The pH of an aqueous fluid which contains a hydratable polymer can beadjusted if necessary to render the fluid compatible with a crosslinkingagent. In other embodiments, a pH adjusting material is added to theaqueous fluid after the addition of the polymer to the aqueous fluid.Typical materials for adjusting the pH are commonly used acids, acidbuffers, and mixtures of acids and bases. For example, sodiumbicarbonate, potassium carbonate, sodium hydroxide, potassium hydroxide,and sodium carbonate are typical pH adjusting agents. Acceptable pHvalues for the fluid may range from neutral to basic, i.e., from about 5to about 14. In other embodiments, the pH is kept neutral or basic,i.e., from about 7 to about 14. In other embodiments, the pH is betweenabout 8 to about 12.

Breaking Agents

The breaking agent may be a metal-based oxidizing agent such as analkaline earth metal or a transition metal. Exemplary breaking agentsinclude, without limitation, magnesium peroxide, calcium peroxide, zincperoxide, or mixtures and combinations thereof.

The term “breaking agent” or “breaker” refers to any chemical that iscapable of reducing the viscosity of a gelled fluid. As described above,after a fracturing fluid is formed and pumped into a subterraneanformation, it is generally desirable to convert the highly viscous gelto a lower viscosity fluid. This allows the fluid to be easily andeffectively removed from the formation and to allow desired material,such as oil or gas, to flow into the well bore. This reduction inviscosity of the treating fluid is commonly referred to as “breaking”Consequently, the chemicals used to break the viscosity of the fluid isreferred to as a breaking agent or a breaker.

There are various methods available for breaking a fracturing fluid or atreating fluid. Typically, fluids break after the passage of time and/orprolonged exposure to high temperatures. However, it is desirable to beable to predict and control the breaking within relatively narrowlimits. Mild oxidizing agents are useful as breakers when a fluid isused in a relatively high temperature formation, although formationtemperatures of 300° F. (149° C.) or higher will generally break thefluid relatively quickly without the aid of an oxidizing agent.

Examples of inorganic breaking agents for use in this invention include,but are not limited to, persulfates, percarbonates, perborates,peroxides, perphosphates, permanganates, etc. Specific examples ofinorganic breaking agents include, but are not limited to, alkalineearth metal persulfates, alkaline earth metal percarbonates, alkalineearth metal perborates, alkaline earth metal peroxides, alkaline earthmetal perphosphates, zinc salts of peroxide, perphosphate, perborate,and percarbonate, and so on. Additional suitable breaking agents aredisclosed in U.S. Pat. Nos. 5,877,127; 5,649,596; 5,669,447; 5,624,886;5,106,518; 6,162,766; and 5,807,812, incorporated herein by reference.In some embodiments, an inorganic breaking agent is selected fromalkaline earth metal or transition metal-based oxidizing agents, such asmagnesium peroxides, zinc peroxides, and calcium peroxides.

In addition, enzymatic breakers may also be used in place of or inaddition to a non-enzymatic breaker. Examples of suitable enzymaticbreakers such as guar specific enzymes, alpha and beta amylases,amyloglucosidase, aligoglucosidase, invertase, maltase, cellulase, andhemi-cellulase are disclosed in U.S. Pat. Nos. 5,806,597 and 5,067,566,incorporated herein by reference.

A breaking agent or breaker may be used “as is” or be encapsulated andactivated by a variety of mechanisms including crushing by formationclosure or dissolution by formation fluids. Such techniques aredisclosed, for example, in U.S. Pat. Nos. 4,506,734; 4,741,401;5,110,486; and 3,163,219, incorporated herein by reference.

Aggregating or Zeta Potential Altering Compositions

Amine-Phosphate Reaction Product Aggregating or Zeta Potential AlteringCompositions

Amines

Suitable amines include, without limitation, any amine that is capableof reacting with a suitable phosphate ester to form a composition thatforms a deformable coating on a metal-oxide-containing surface.Exemplary examples of such amines include, without limitation, any amineof the general formula R¹,R²NH or mixtures or combinations thereof,where R¹ and R² are independently a hydrogen atom or a carbyl grouphaving between about between about 1 and 40 carbon atoms and therequired hydrogen atoms to satisfy the valence and where one or more ofthe carbon atoms can be replaced by one or more hetero atoms selectedfrom the group consisting of boron, nitrogen, oxygen, phosphorus, sulfuror mixture or combinations thereof and where one or more of the hydrogenatoms can be replaced by one or more single valence atoms selected fromthe group consisting of fluorine, chlorine, bromine, iodine or mixturesor combinations thereof. Exemplary examples of amines suitable for usein this invention include, without limitation, aniline and alkylanilines or mixtures of alkyl anilines, pyridines and alkyl pyridines ormixtures of alkyl pyridines, pyrrole and alkyl pyrroles or mixtures ofalkyl pyrroles, piperidine and alkyl piperidines or mixtures of alkylpiperidines, pyrrolidine and alkyl pyrrolidines or mixtures of alkylpyrrolidines, indole and alkyl indoles or mixture of alkyl indoles,imidazole and alkyl imidazole or mixtures of alkyl imidazole, quinolineand alkyl quinoline or mixture of alkyl quinoline, isoquinoline andalkyl isoquinoline or mixture of alkyl isoquinoline, pyrazine and alkylpyrazine or mixture of alkyl pyrazine, quinoxaline and alkyl quinoxalineor mixture of alkyl quinoxaline, acridine and alkyl acridine or mixtureof alkyl acridine, pyrimidine and alkyl pyrimidine or mixture of alkylpyrimidine, quinazoline and alkyl quinazoline or mixture of alkylquinazoline, or mixtures or combinations thereof.

Phosphate Compounds

Suitable phosphate compounds include, without limitation, any phosphateester that is capable of reacting with a suitable amine to form acomposition that forms a deformable coating on a metal-oxide containingsurface or partially or completely coats particulate materials.Exemplary examples of such phosphate esters include, without limitation,any phosphate esters of the general formula P(O)(OR³)(OR⁴)(OR⁵),polymers thereof, or mixture or combinations thereof, where R³, R⁴, andOR⁵ are independently a hydrogen atom or a carbyl group having betweenabout between about 1 and 40 carbon atoms and the required hydrogenatoms to satisfy the valence and where one or more of the carbon atomscan be replaced by one or more hetero atoms selected from the groupconsisting of boron, nitrogen, oxygen, phosphorus, sulfur or mixture orcombinations thereof and where one or more of the hydrogen atoms can bereplaced by one or more single valence atoms selected from the groupconsisting of fluorine, chlorine, bromine, iodine or mixtures orcombinations thereof. Exemplary examples of phosphate esters include,without limitation, phosphate ester of alkanols having the generalformula P(O)(OH)_(x)(OR⁶), where x+y=3 and are independently a hydrogenatom or a carbyl group having between about between about 1 and 40carbon atoms and the required hydrogen atoms to satisfy the valence andwhere one or more of the carbon atoms can be replaced by one or morehetero atoms selected from the group consisting of boron, nitrogen,oxygen, phosphorus, sulfur or mixture or combinations thereof and whereone or more of the hydrogen atoms can be replaced by one or more singlevalence atoms selected from the group consisting of fluorine, chlorine,bromine, iodine or mixtures or combinations thereof such as ethoxyphosphate, propoxyl phosphate or higher alkoxy phosphates or mixtures orcombinations thereof. Other exemplary examples of phosphate estersinclude, without limitation, phosphate esters of alkanol amines havingthe general formula N[R⁷OP(O)(OH)₂]₃ where R⁷ is a carbenyl group havingbetween about between about 1 and 40 carbon atoms and the requiredhydrogen atoms to satisfy the valence and where one or more of thecarbon atoms can be replaced by one or more hetero atoms selected fromthe group consisting of boron, nitrogen, oxygen, phosphorus, sulfur ormixture or combinations thereof and where one or more of the hydrogenatoms can be replaced by one or more single valence atoms selected fromthe group consisting of fluorine, chlorine, bromine, iodine or mixturesor combinations thereof group including the tri-phosphate ester oftri-ethanol amine or mixtures or combinations thereof. Other exemplaryexamples of phosphate esters include, without limitation, phosphateesters of hydroxylated aromatics such as phosphate esters of alkylatedphenols such as Nonylphenyl phosphate ester or phenolic phosphateesters. Other exemplary examples of phosphate esters include, withoutlimitation, phosphate esters of diols and polyols such as phosphateesters of ethylene glycol, propylene glycol, or higher glycolicstructures. Other exemplary phosphate esters include any phosphate esterthan can react with an amine and coated on to a substrate forms adeformable coating enhancing the aggregating potential of the substrate.

Polymeric Amine Zeta Potential Aggregating Compositions

Suitable amines capable of forming a deformable coating on a solidparticles, surfaces, and/or materials include, without limitation,heterocyclic aromatic amines, substituted heterocyclic aromatic amines,poly vinyl heterocyclic aromatic amines, co-polymers of vinylheterocyclic aromatic amine and non amine polymerizable monomers(ethylenically unsaturated monomers and diene monomers), or mixtures orcombinations thereof, where the substituents of the substitutedheterocyclic aromatic amines are carbyl groups having between aboutbetween about 1 and 40 carbon atoms and the required hydrogen atoms tosatisfy the valence and where one or more of the carbon atoms can bereplaced by one or more hetero atoms selected from the group consistingof boron, nitrogen, oxygen, phosphorus, sulfur or mixture orcombinations thereof and where one or more of the hydrogen atoms can bereplaced by one or more single valence atoms selected from the groupconsisting of fluorine, chlorine, bromine, iodine or mixtures orcombinations thereof. In certain embodiments, amines suitable for use inthis invention include, without limitation, aniline and alkyl anilinesor mixtures of alkyl anilines, pyridines and alkyl pyridines or mixturesof alkyl pyridines, pyrrole and alkyl pyrroles or mixtures of alkylpyrroles, piperidine and alkyl piperidines or mixtures of alkylpiperidines, pyrrolidine and alkyl pyrrolidines or mixtures of alkylpyrrolidines, indole and alkyl indoles or mixture of alkyl indoles,imidazole and alkyl imidazole or mixtures of alkyl imidazole, quinolineand alkyl quinoline or mixture of alkyl quinoline, isoquinoline andalkyl isoquinoline or mixture of alkyl isoquinoline, pyrazine and alkylpyrazine or mixture of alkyl pyrazine, quinoxaline and alkyl quinoxalineor mixture of alkyl quinoxaline, acridine and alkyl acridine or mixtureof alkyl acridine, pyrimidine and alkyl pyrimidine or mixture of alkylpyrimidine, quinazoline and alkyl quinazoline or mixture of alkylquinazoline, or mixtures or combinations thereof. In certainembodiments, the poly vinyl heterocyclic amines include, withoutlimitation, polymers and copolymers of vinyl pyridine, vinyl substitutedpyridine, vinyl pyrrole, vinyl substituted pyrroles, vinyl piperidine,vinyl substituted piperidines, vinyl pyrrolidine, vinyl substitutedpyrrolidines, vinyl indole, vinyl substituted indoles, vinyl imidazole,vinyl substituted imidazole, vinyl quinoline, vinyl substitutedquinoline, vinyl isoquinoline, vinyl substituted isoquinoline, vinylpyrazine, vinyl substituted pyrazine, vinyl quinoxaline, vinylsubstituted quinoxaline, vinyl acridine, vinyl substituted acridine,vinyl pyrimidine, vinyl substituted pyrimidine, vinyl quinazoline, vinylsubstituted quinazoline, or mixtures and combinations thereof. Incertain embodiments, the heterocyclic aromatic amines comprise HAP™-310available from Vertellus Specialties Inc.

Suitable alternate aggregating compositions comprise: (1) oligomericamines (oligoamines) and/or polymeric amines (polyamines), (2)oligoamines and/or polyamines including an effective amount ofquaternized amine groups, N-oxide groups, or mixtures of quaternizedamine groups and N-oxide groups, or (3) mixtures and combinationsthereof, where the effective is sufficient to render the compositionscapable of forming partial, substantially complete, and/or completecoatings on the solid particles, surfaces and/or materials depending onthe properties of the solid particles, surfaces and/or materials to betreated. The oligomeric and/or polymeric amines include repeat units ofethylenically unsaturated polymerizable monomers (vinyl and dienemonomers) including an amine group, a heterocyclic amine group, anaromatic amine group, substituted analogs thereof, or mixtures andcombinations thereof. The oligomeric and/or polymeric amines may alsoinclude repeat units of non-amine containing ethylenically unsaturatedpolymerizable monomers (vinyl and diene monomers). In certainembodiments, the aggregating compositions of this invention may alsoinclude reaction products of the aggregating compositions of thisinvention with a phosphate component. In certain embodiments, theaggregating compositions may also include reaction products ofpolyamines having 2 to 10 amino groups and phosphate compounds. In otherembodiments, the aggregating compositions of this invention may alsoinclude ethoxylated alcohols and/or glymes. The aggregating compositionsof this invention are believed to form complete, substantially complete,and/or partial coatings on the particles, surfaces, and/or materialsaltering self-aggregating properties, and/or aggregation propensities ofthe particles, surfaces, and/or materials. In certain embodiments, theoligomers and polymers may be of any form from homooligomers,homopolymers, random cooligomers, random copolymers, fully blockedcooligomers, fully blocked copolymers, partially blocked cooligomers,partially blocked copolymers, random, fully blocked, and/or partiallyblocked oligomers and polymers including three or more different type ofmonomeric repeat units, any other combination of two or more monomericrepeat units, or mixtures and combinations thereof to achieve desiredproperties so that the compositions forms partially or complete zetaaltering coatings on specific formation surfaces, specific formationparticles, and/or specific proppants. In other embodiments, thecompositions include oligomers and/or polymers having differing amountsof non-amine containing monomeric repeat units, amine containingmonomeric repeat units, quaternary amine containing monomeric repeatunits, and N-oxide containing monomeric repeat units, where the amountsare adjusted so that the compositions are tailored to have specificproperties to form coatings on specific solid materials, surfaces and/orsubstrates. The tailoring may also be based on different amounts ofdifferent oligomers and/or polymers in the formulation.

Amine Component and Amine-Phosphate Reaction Product AggregatingCompositions

Suitable amines for the amine component include, without limitation, anamine of the general formula R¹,R²NH or mixtures or combinationsthereof, where R¹ and R² are independently a hydrogen atom or a carbylgroup having between about between about 1 and 40 carbon atoms and therequired hydrogen atoms to satisfy the valence, where at least R¹ or R²is a nitrogen containing heterocycle, and where one or more of thecarbon atoms can be replaced by one or more hetero atoms selected fromthe group consisting of boron, nitrogen, oxygen, phosphorus, sulfur ormixture or combinations thereof and where one or more of the hydrogenatoms can be replaced by one or more single valence atoms selected fromthe group consisting of fluorine, chlorine, bromine, iodine or mixturesor combinations thereof. Exemplary examples of amines suitable for usein this invention include, without limitation, pyridines and alkylpyridines or mixtures of alkyl pyridines, pyrrole and alkyl pyrroles ormixtures of alkyl pyrroles, piperidine and alkyl piperidines or mixturesof alkyl piperidines, pyrrolidine and alkyl pyrrolidines or mixtures ofalkyl pyrrolidines, indole and alkyl indoles or mixture of alkylindoles, imidazole and alkyl imidazole or mixtures of alkyl imidazole,quinoline and alkyl quinoline or mixture of alkyl quinoline,isoquinoline and alkyl isoquinoline or mixture of alkyl isoquinoline,pyrazine and alkyl pyrazine or mixture of alkyl pyrazine, quinoxalineand alkyl quinoxaline or mixture of alkyl quinoxaline, acridine andalkyl acridine or mixture of alkyl acridine, pyrimidine and alkylpyrimidine or mixture of alkyl pyrimidine, quinazoline and alkylquinazoline or mixture of alkyl quinazoline, or mixtures or combinationsthereof. In certain embodiments, the amines of the amine componentscomprise alkyl pyridines.

Amine Polymeric Zeta Potential Aggregating Compositions

Suitable polymers for use in the compositions of this inventionincludes, without limitation, any polymer including repeat units derivedfrom a heterocyclic or heterocyclic aromatic vinyl monomer, where thehetero atoms is a nitrogen atom or a combination of a nitrogen atom andanother hetero atoms selected from the group consisting of boron,oxygen, phosphorus, sulfur, germanium, and/or. The polymers can behomopolymers of cyclic or aromatic nitrogen-containing vinyl monomers,or copolymers of any ethylenically unsaturated monomers that willcopolymerize with a cyclic or aromatic nitrogen-containing vinylmonomer. Exemplary cyclic or aromatic nitrogen-containing vinyl monomersinclude, without limitation, vinyl pyrroles, substituted vinyl pyrroles,vinyl pyridines, substituted vinyl pyridines, vinyl quinolines orsubstituted vinyl quinolines, vinyl anilines or substituted vinylanilines, vinyl piperidines or substituted vinyl piperidines, vinylpirrolidines or substituted vinyl pyrrolidines, vinyl imidazole orsubstituted vinyl imidazole, vinyl pyrazine or substituted vinylpyrazines, vinyl pyrimidine or substituted vinyl pyrimidine, vinylquinazoline or substituted vinyl quinazoline, or mixtures orcombinations thereof. Exemplary pyridine monomer include 2-vinylpyridine, 4-vinyl pyridine, or mixtures or combinations thereof.Exemplary homopolymers include poly-2-vinyl pyridine, poly-4-vinylpyridine, and mixtures or combinations thereof. Exemplary copolymersincluding copolymers or 2-vinyl pyridine and 4-vinyl pyridine,copolymers of ethylene and 2-vinyl pyridine and/or 4-vinyl pyridine,copolymers of propylene and 2-vinyl pyridine and/or 4-vinyl pyridine,copolymers of acrylic acid and 2-vinyl pyridine and/or 4-vinyl pyridine,copolymers of methacrylic acid and 2-vinyl pyridine and/or 4-vinylpyridine, copolymers of acrylates and 2-vinyl pyridine and/or 4-vinylpyridine, copolymers of methacrylates and 2-vinyl pyridine and/or4-vinyl pyridine, and mixtures of combinations thereof. All of thesemonomers can also includes substituents. Moreover, in all these vinylmonomers or ethylenically unsaturated monomers, one or more of thecarbon atoms can be replaced by one or more hetero atoms selected fromthe group consisting of boron, oxygen, phosphorus, sulfur or mixture orcombinations thereof and where one or more of the hydrogen atoms can bereplaced by one or more single valence atoms selected from the groupconsisting of fluorine, chlorine, bromine, iodine or mixtures orcombinations thereof. Of course, all of these monomers includes at leastone nitrogen atom in the structure.

Examples of vinyl amine polymers covered in Weatherford U.S. Pat. No.8,466,094.

From the claims: poly-2-vinyl pyridine, poly-4-vinyl pyridine, andmixtures or combinations thereof and copolymers selected from the groupconsisting of copolymers of 2-vinyl pyridine and 4-vinyl pyridine,copolymers of ethylene and 2-vinyl pyridine and/or 4-vinyl pyridine,copolymers of propylene and 2-vinyl pyridine and/or 4-vinyl pyridine,copolymers of acrylic acid and 2-vinyl pyridine and/or 4-vinyl pyridine,copolymers of methacrylic acid and 2-vinyl pyridine and/or 4-vinylpyridine, copolymers of acrylates and 2-vinyl pyridine and/or 4-vinylpyridine, copolymers of methacrylates and 2-vinyl pyridine and/or4-vinyl pyridine, and mixtures or combinations thereof and optionally areaction product of an amine and a phosphate-containing compound.

Suitable polymers for use in the compositions of this inventionincludes, without limitation, any polymer including repeat units derivedfrom a heterocyclic or heterocyclic aromatic vinyl monomer, where thehetero atoms is a nitrogen atom or a combination of a nitrogen atom andanother hetero atoms selected from the group consisting of boron,oxygen, phosphorus, sulfur, germanium, and/or mixtures thereof. Thepolymers can be homopolymers of cyclic or aromatic nitrogen-containingvinyl monomers, or copolymers of any ethylenically unsaturated monomersthat will copolymerize with a cyclic or aromatic nitrogen-containingvinyl monomer. Exemplary cyclic or aromatic nitrogen-containing vinylmonomers include, without limitation, vinyl pyrroles, substituted vinylpyrroles, vinyl pyridines, substituted vinyl pyridines, vinyl quinolinesor substituted vinyl quinolines, vinyl anilines or substituted vinylanilines, vinyl piperidines or substituted vinyl piperidines, vinylpyrrolidines or substituted vinyl pyrrolidines, vinyl imidazole orsubstituted vinyl imidazole, vinyl pyrazine or substituted vinylpyrazines, vinyl pyrimidine or substituted vinyl pyrimidine, vinylquinazoline or substituted vinyl quinazoline, or mixtures orcombinations thereof.

For further details on the aggregating compositions used in thisinvention the reader is referred to U.S. Pat. Nos. 7,392,847; 7,956,017;8,466,094; and 8,871,694; and United States Pub. Nos. 20100212905, and20130075100.

Coacervates Aggregating Compositions

The surfactant which is oppositely charged from the polymer is sometimescalled herein the “counterionic surfactant.” By this we mean asurfactant having a charge opposite that of the polymer.

Suitable cationic polymers include polyamines, quaternary derivatives ofcellulose ethers, quaternary derivatives of guar, homopolymers andcopolymers of at least 20 mole percent dimethyl diallyl ammoniumchloride (DMDAAC), homopolymers and copolymers of methacrylamidopropyltrimethyl ammonium chloride (MAPTAC), homopolymers and copolymers ofacrylamidopropyl trimethyl ammonium chloride (APTAC), homopolymers andcopolymers of methacryloyloxyethyl trimethyl ammonium chloride (METAC),homopolymers and copolymers of acryloyloxyethyl trimethyl ammoniumchloride (AETAC), homopolymers and copolymers of methacryloyloxyethyltrimethyl ammonium methyl sulfate (METAMS), and quaternary derivativesof starch.

Suitable anionic polymers include homopolymers and copolymers of acrylicacid (AA), homopolymers and copolymers of methacrylic acid (MAA),homopolymers and copolymers of 2-acrylamido-2-methylpropane sulfonicacid (AMPSA), homopolymers and copolymers of N-methacrylamidopropylN,N-dimethyl amino acetic acid, N-acrylamidopropyl N,N-dimethyl aminoacetic acid, N-methacryloyloxyethyl N,N-dimethyl amino acetic acid, andN-acryloyloxyethyl N,N-dimethyl amino acetic acid.

Anionic surfactants suitable for use with the cationic polymers includealkyl, aryl or alkyl aryl sulfates, alkyl, aryl or alkyl arylcarboxylates or alkyl, aryl or alkyl aryl sulfonates. Preferably, thealkyl moieties have about 1 to about 18 carbons, the aryl moieties haveabout 6 to about 12 carbons, and the alkyl aryl moieties have about 7 toabout 30 carbons. Exemplary groups would be propyl, butyl, hexyl, decyl,dodecyl, phenyl, benzyl and linear or branched alkyl benzene derivativesof the carboxylates, sulfates and sulfonates. Included are alkyl ethersulphates, alkaryl sulphonates, alkyl succinates, alkylsulphosuccinates, N-alkoyl sarcosinates, alkyl phosphates, alkyl etherphosphates, alkyl ether carboxylates, alpha-olefin sulphonates and acylmethyl taurates, especially their sodium, magnesium ammonium and mono-,di- and triethanolamine salts. The alkyl and acyl groups generallycontain from 8 to 18 carbon atoms and may be unsaturated. The alkylether sulphates, alkyl ether phosphates and alkyl ether carboxylates maycontain from one to 10 ethylene oxide or propylene oxide units permolecule, and preferably contain 2 to 3 ethylene oxide units permolecule. Examples of suitable anionic surfactants include sodium laurylsulphate, sodium lauryl ether sulphate, ammonium lauryl sulphosuccinate,ammonium lauryl sulphate, ammonium lauryl ether sulphate, sodiumdodecylbenzene sulphonate, triethanolamine dodecylbenzene sulphonate,sodium cocoyl isethionate, sodium lauroyl isethionate, and sodiumN-lauryl sarcosinate.

Cationic surfactants suitable for use with the anionic polymers includequaternary ammonium surfactants of the formula X⁻N⁺R¹R²R³ where R¹, R²,and R³ are independently selected from hydrogen, an aliphatic group offrom about 1 to about 22 carbon atoms, or aromatic, aryl, an alkoxy,polyoxyalkylene, alkylamido, hydroxyalkyl, or alkylaryl group havingfrom about 1 to about 22 carbon atoms; and X is an anion selected fromhalogen, acetate, phosphate, nitrate, sulfate, alkylsulfate radicals(e.g., methyl sulfate and ethyl sulfate), tosylate, lactate, citrate,and glycolate. The aliphatic groups may contain, in addition to carbonand hydrogen atoms, ether linkages, and other groups such as hydroxy oramino group substituents (e.g., the alkyl groups can containpolyethylene glycol and polypropylene glycol moieties). The longer chainaliphatic groups, e.g., those of about 12 carbons, or higher, can besaturated or unsaturated. More preferably, R¹ is an alkyl group havingfrom about 12 to about 18 carbon atoms; R² is selected from H or analkyl group having from about 1 to about 18 carbon atoms; R³ and R⁴ areindependently selected from H or an alkyl group having from about 1 toabout 3 carbon atoms; and X is as described above.

Suitable hydrophobic alcohols having 6-23 carbon atoms are linear orbranched alkyl alcohols of the general formula C_(M)H_(2M+2−N)(OH)_(N),where M is a number from 6-23, and N is 1 when M is 6-12, but where M is13-23, N may be a number from 1 to 3. Our most preferred hydrophobicalcohol is lauryl alcohol, but any linear monohydroxy alcohol having8-15 carbon atoms is also preferable to an alcohol with more or fewercarbon atoms.

By a gel promoter we mean a betaine, a sultaine or hydroxysultaine, oran amine oxide. Examples of betaines include the higher alkyl betainessuch as coco dimethyl carboxymethyl betaine, lauryl dimethylcarboxymethyl betaine, lauryl dimethyl alphacarboxyethyl betaine, cetyldimethyl carboxymethyl betaine, cetyl dimethyl betaine, laurylbis-(2-hydroxyethyl)carboxymethyl betaine, oleyl dimethylgamma-carboxypropyl betaine, laurylbis-(2-hydroxypropyl)alpha-carboxyethyl betaine, coco dimethylsulfopropyl betaine, lauryl dimethyl sulfoethyl betaine, laurylbis-(2-hydroxyethyl)sulfopropyl betaine, amidobetaines andamidosulfobetaines (wherein the RCONH(CH₂)₃ radical is attached to thenitrogen atom of the betaine, oleyl betaine, and cocamidopropyl betaine.Examples of sultaines and hydroxysultaines include materials such ascocamidopropyl hydroxysultaine.

By a Zeta potential having an absolute value of at least 20 we mean aZeta potential having a value of +20 of higher or −20 or lower.

Amphoteric surfactants suitable for use with either cationic polymers oranionic polymers include those surfactants broadly described asderivatives of aliphatic secondary and tertiary amines in which thealiphatic radical can be straight or branched chain and wherein one ofthe aliphatic substituents contains from about 8 to about 18 carbonatoms and one contains an anionic water solubilizing group such ascarboxy, sulfonate, sulfate, phosphate, or phosphonate. Suitableamphoteric surfactants include derivatives of aliphatic secondary andtertiary amines in which the aliphatic radical can be straight orbranched chain and wherein one of the aliphatic aliphatic substituentscontains from about 8 to about 18 carbon atoms and one contains ananionic water solubilizing group, e.g., carboxy, sulfonate, sulfate,phosphate, or phosphonate. Examples of compounds falling within thisdefinition are sodium 3-dodecylaminopropionate, and sodium3-dodecylaminopropane sulfonate.

Suitable amine oxides include cocoamidopropyl dimethyl amine oxide andother compounds of the formula R¹R²R³N→O wherein R³ is a hydrocarbyl orsubstituted hydrocarbyl having from about 8 to about 30 carbon atoms,and R¹ and R² are independently hydrogen, a hydrocarbyl or substitutedhydrocarbyl having up to 30 carbon atoms. Preferably, R³ is an aliphaticor substituted aliphatic hydrocarbyl having at least about 12 and up toabout 24 carbon atoms. More preferably R³ is an aliphatic group havingat least about 12 carbon atoms and having up to about 22, and mostpreferably an aliphatic group having at least about 18 and no more thanabout 22 carbon atoms.

Suitable phosphorus-containing compounds suitable for use in theinvention include, without limitation, phosphates or phosphateequivalents or mixtures or combinations thereof. Suitable phosphatesinclude, without limitation, mono-alkali metal phosphates (PO(OH)(OM),where M is Li, Na, K, Rd, or Cs), di-alkali metal phosphates(PO(OH)(OM)₂, where each M is the same or different and is Li, Na, K,Rd, or Cs) such as dipotassium phosphate (PO(OH)(OK)₂) and disodiumphosphate, (PO(OH)(ONa)₂), tri-alkali metal phosphates (PO(OM)₃, whereeach M is the same or different and is Li, Na, K, Rd, or Cs) such astrisodium phosphate (PO(ONa)₃) and tripotassium phosphate (PO(OK)₃),carbyl phosphates (PO(OR¹)(OM)₂, where R¹ is a carbyl group and M is H,Li, Na, K, Rd, and/or Cs), dicarbyl phosphates (PO(OR¹)(OR²)(OM), whereR¹ and R² are the same or different carbyl groups and M is H, Li, Na, K,Rd, or Cs), tricarbyl phosphates (PO(OR¹)(OR²)(OR³), where R¹, R², andR³ are the same or different carbyl groups), or mixtures or combinationsthereof.

Suitable carbyl group include, without limitations, carbyl group havingbetween about 3 and 40 carbon atoms, where one or more of the carbonatoms can be replaced with a hetero atom selected from the groupconsisting of oxygen and nitrogen, with the remainder of valencescomprising hydrogen or a mono-valent group such as a halogen, an amide(—NHCOR), an alkoxide (—OR), or the like, where R is a carbyl group. Thecarbyl group can be an alkyl group, an alkenyl group, an aryl group, analkaaryl group, an aryalkyl group, or mixtures or combinations thereof,i.e., each carbyl group in the phosphate can be the same or different.In certain embodiments, the carbyl group has between about 3 and about20, where one or more of the carbon atoms can be replaced with a heteroatom selected from the group consisting of oxygen and nitrogen, with theremainder of valences comprising hydrogen or a mono-valent group such asa halogen, an amide (—NHCOR), an alkoxide (—OR), or the like, where R isa carbyl group. In certain embodiments, the carbyl group has betweenabout 3 and about 16, where one or more of the carbon atoms can bereplaced with a hetero atom selected from the group consisting of oxygenand nitrogen, with the remainder of valences comprising hydrogen or amono-valent group such as a halogen, an amide (—NHCOR), an alkoxide(—OR), or the like, where R is a carbyl group. In certain embodiments,the carbyl group has between about 3 and about 12, where one or more ofthe carbon atoms can be replaced with a hetero atom selected from thegroup consisting of oxygen and nitrogen, with the remainder of valencescomprising hydrogen or a mono-valent group such as a halogen, an amide(—NHCOR), an alkoxide (—OR), or the like, where R is a carbyl group. Incertain embodiments, the carbyl group has between about 4 and about 8,where one or more of the carbon atoms can be replaced with a hetero atomselected from the group consisting of oxygen and nitrogen, with theremainder of valences comprising hydrogen or a mono-valent group such asa halogen, an amide (—NHCOR), an alkoxide (—OR), or the like, where R isa carbyl group.

Suitable tri-alkyl phosphates include, without limitations, alkyl grouphaving from about 3 to about 20 carbon atoms, where one or more of thecarbon atoms can be replaced with a hetero atom selected from the groupconsisting of oxygen and nitrogen, with the remainder of valencescomprising hydrogen or a mono-valent group such as a halogen, an amide(—NHCOR), an alkoxide (—OR), or the like, where R is a carbyl group. Incertain embodiments, the tri-alkyl phosphate includes alkyl groupshaving from about 4 to about 12 carbon atoms, where one or more of thecarbon atoms can be replaced with a hetero atom selected from the groupconsisting of oxygen and nitrogen, with the remainder of valencescomprising hydrogen or a mono-valent group such as a halogen, an amide(—NHCOR), an alkoxide (—OR), or the like, where R is a carbyl group. Inother embodiments, the tri-alkyl phosphate includes alkyl groups havingfrom about 4 to about 8 carbon atoms, where one or more of the carbonatoms can be replaced with a hetero atom selected from the groupconsisting of oxygen and nitrogen, with the remainder of valencescomprising hydrogen or a mono-valent group such as a halogen, an amide(—NHCOR), an alkoxide (—OR), or the like, where R is a carbyl group.Such phosphates can be produced by reacting a phosphate donor such asphosphorus pentoxide and a mixture of alcohols in desired proportions.

Solid Materials and Proppants

Suitable solid materials and/or proppants capable of being pre-treatedor treated with the aggregating compositions of this invention include,without limitation, metal oxides and/or ceramics, natural or synthetic,metals, plastics and/or other polymeric solids, solid materials derivedfrom plants, any other solid material that does or may find use indownhole applications, treated analogs thereof, where solid materialsand/or proppants are treated with the aggregating compositions of thisinvention, or mixtures or combinations thereof. Metal oxides includingany solid oxide of a metallic element of the periodic table of elements.Exemplary examples of metal oxides and ceramics include actinium oxides,aluminum oxides, antimony oxides, boron oxides, barium oxides, bismuthoxides, calcium oxides, cerium oxides, cobalt oxides, chromium oxides,cesium oxides, copper oxides, dysprosium oxides, erbium oxides, europiumoxides, gallium oxides, germanium oxides, iridium oxides, iron oxides,lanthanum oxides, lithium oxides, magnesium oxides, manganese oxides,molybdenum oxides, niobium oxides, neodymium oxides, nickel oxides,osmium oxides, palladium oxides, potassium oxides, promethium oxides,praseodymium oxides, platinum oxides, rubidium oxides, rhenium oxides,rhodium oxides, ruthenium oxides, scandium oxides, selenium oxides,silicon oxides, samarium oxides, silver oxides, sodium oxides, strontiumoxides, tantalum oxides, terbium oxides, tellurium oxides, thoriumoxides, tin oxides, titanium oxides, thallium oxides, thulium oxides,vanadium oxides, tungsten oxides, yttrium oxides, ytterbium oxides, zincoxides, zirconium oxides, ceramic structures prepared from one or moreof these oxides and mixed metal oxides including two or more of theabove listed metal oxides. Exemplary examples of plant materialsinclude, without limitation, shells of seed bearing plants such aswalnut shells, pecan shells, peanut shells, shells for other hardshelled seed forming plants, ground wood or other fibrous cellulosicmaterials, or mixtures or combinations thereof.

Examples of suitable proppants include, but are not limited to, quartzsand grains, glass and ceramic beads, walnut shell fragments, aluminumpellets, nylon pellets, and the like. Proppants are typically used inconcentrations between about 1 to 8 lbs. per gallon of a fracturingfluid, although higher or lower concentrations may also be used asdesired.

Sand, resin-coated sand, and ceramic particles are the most commonlyused proppants, though the literature, for instance U.S. Pat. No.4,654,266, incorporated herein by reference, also mentions the used ofwalnut hull fragments coated with some bonding additives, metallicshots, or metal-coated beads—nearly spherical but having a passagewaysto improve their conductibility.

The proppant conductivity is affected principally by two parameters, theproppant pack width and the proppant pack permeability. To improvefracture proppant conductivity, typical approaches include high largediameter proppants. More generally, the most common approaches toimprove proppant fracture performance include high strength proppants,large diameter proppants, high proppant concentrations in the proppantpack to obtain wider propped fractures, conductivity enhancing materialssuch as breakers, flow-back aides, fibers and other material thatphysically alter proppant packing, and use of non-damaging fracturingfluids such as gelled oils, viscoelastic surfactant based fluids, foamedfluids or emulsified fluids. It is also recognized that grain size,grain-size distribution, quantity of fines and impurities, roundness andsphericity and proppant density have an impact on fracture conductivity.

As mentioned above, the main function of the proppant is to keep thefracture open by overcoming the in-situ stress. Where the proppantstrength is not high enough, the closure stress crushes the proppant,creating fines and reducing the conductivity. Sand is typically suitablefor closure stresses of less than about 6000 psi (41 MPa), resin-coatedsand may be used up to about 8000 psi (55 MPa). Intermediate-strengthproppant typically consists of fused ceramic or sintered-bauxite and isused for closure stresses ranging between 5000 psi and 10000 psi (34 MPato 69 MPa). High-strength proppant, consisting of sintered-bauxite withlarge amounts of corundum is used at closure stresses of up to about14000 psi (96 MPa).

Permeability of a propped fracture increases as the square of the graindiameter. However, larger grains are often more susceptible to crush,have more placement problems and tend to be more easily invaded byfines. As the result, the average conductivity over the life of a wellmay be actually higher with smaller proppants.

It should be recognized that the proppant itself is may be of any shapeincluding irregular shapes, essentially spherical shapes, elongatedshapes, etc. Adding fibers or fiber-like products to the fluids maycontribute to a reduction of the proppant flowback and consequently to abetter packing of the proppant islands in the fracture, as the fiberswill adhere to the islands because the islands include an amount ofproppants coated with an aggregating composition of this invention ortreated with an aggregating composition and a coating crosslinkingcomposition. Additionally, the fibers may prevent or reduce finemigrations and consequently, prevent or reduce a reduction of theproppant conductivity by forming new types of proppant islands that willlead to higher formation conductivity.

Fibers and Organic Particulate Materials

Non-Erodible Fibers

Suitable non soluble or non erodible fibers include, without limitation,natural fibers, synthetic fibers, or mixtures and combinations thereof.Exemplary examples of natural fibers include, without limitation, abaca,cellulose, wool such as alpaca wool, cashmere wool, mohair, or angorawool, camel hair, coir, cotton, flax, hemp, jute, ramie, silk, sisal,byssus fibers, chiengora fibers, muskox wool, yak wool, rabbit hair,kapok, kenaf, raffia, bamboo, Piiia, asbestos fibers, glass fibers,cellulose fibers, wood pulp fibers, treated analogs thereof, or mixturesand combinations thereof. Exemplary examples of synthetic fibersinclude, without limitation, regenerated cellulose fibers, celluloseacetate fibers, polyester fibers, aramid fibers, acrylic fibers, fibreoptic fibers, polyamide and polyester fibers, polyethylene fibers,polypropylene fibers, acrylic fibers, aramid fibers, silk fibers, azlonfibers, BAN-LON® fibers (registered trademark of Joseph Bancroft & SonsCompany), basalt fiber, carbon fiber, CELLIANT® fiber (registeredtrademark of Hologenix, LLC), cellulose acetate fiber, cellulosetriacetate fibers, CORDURA® fibers (registered trademark of INVISTA, asubsidiary of privately owned Koch Industries, Inc.), crimplene (apolyester) fibers, cuben fibers, cuprammonium rayon fibers, dynelfibers, elasterell fibers, elastolefin fibers, glass fibers, GOLD FLEX®fibers (registered trademark of Honeywell), INNEGRA S™ fibers (brandnameof Innegra Technologies LLC), aramid fibers such as KEVLAR® fibers(registered trademark of DuPont), KEVLAR® KM2 fibers (registeredtrademark of DuPont), LASTOL® fibers (registered trademark of DOWChemicals Company), Lyocell fibers, M5 fibers, modacrylic fibers, Modalfibers, NOMEX® fibers (registered trademark of DuPont), nylon fiberssuch as nylon 4 fibers, nylon 6 fibers, nylon 6-6 fibers, polyolefinfibers, poly(p-phenylene sulfide) fibers, polyacrylonitrile fibers,polybenzimidazole fibers, polydioxanone fibers, polyester fibers, qianafibers, rayon fibers, polyvinylidene chloride fibers such as Saranfibers, of poly(trimethylene terephthalate) fibers such as Soronafibers, spandex or elastane fibers, Taklon fibers, Technora fibers,THINSULATE® fibers (registered trademark of 3M), Twaron™ fibers(brandname of Teij in Aramid), ultra-high-molecular-weight polyethylenefibers, syndiotactic polypropylene fibers, isotactic polypropylenefibers, polyvinylalcohol fibers, cellulose xanthate fibers,poly(p-phenylene-2,6-benzobisoxazole) fibers, polyimide fibers, othersynthetic fibers, or mixtures and combinations thereof. These fibers canadditionally or alternatively form a three-dimensional network,reinforcing the proppant and limiting its flowback.

Non-Erodible Particles

Suitable solid organic polymeric particulate materials include, withoutlimitation, polymeric particulate matter derived from cellulose, acrylicacid, aramides, acrylonitrile, polyamides, vinylidene, olefins,diolefins, polyester, polyurethane, vinyl alcohol, and vinyl chloride,may be used. Preferred compositions, assuming the required reactivityand/or decomposition characteristics may be selected from rayon,acetate, triacetate, cotton, wool (cellulose group); nylon, acrylic,modacrylic, nitrile, polyester, saran, spandex, vinyon, olefin, vinyl,(synthetic polymer group); azlon, rubber (protein and rubber group), andmixtures thereof. Polyester and polyamide particles of sufficientmolecular weight, such as from Dacron® and nylon, respectively, andmixtures thereof, are most preferred. Again, composite particles,comprising natural and/or synthetic materials of appropriatecharacteristics, may be employed. For example, a suitable compositeparticle might comprise a core and sheath structure where the sheathmaterial and the core material degrade over different desired periods oftime. The compounds or compositions employed as organic polymericmaterial according to the invention need not be pure, and commerciallyavailable materials containing various additives, fillers, etc. orhaving coatings may be used, so long as such components do not interferewith the required activity. The organic polymeric particulate materiallevel, i.e., concentration, provided initially in the fluid may rangefrom 0.02 percent up to about 10 percent by weight of the fluid. Mostpreferably, however, the concentration ranges from about 0.02 percent toabout 5.0 percent by weight of fluid.

Particle size and shape, while important, may be varied considerably,depending on timing and transport considerations. In certainembodiments, if irregular or spherical particles of the organic polymerare used, particle size may range from 80 mesh to 2.5 mesh (Tyler),preferably from 60 mesh to 3 mesh. Fibers and/or platelets of thespecified polymeric materials are preferred for their mobility andtransfer aiding capability. In the case of fibers of the organicpolymer, the fibers employed according to the invention may also have awide range of dimensions and properties. As employed herein, the term“fibers” refers to bodies or masses, such as filaments, of natural orsynthetic material(s) having one dimension significantly longer than theother two, which are at least similar in size, and further includesmixtures of such materials having multiple sizes and types. In otherembodiments, individual fiber lengths may range upwardly from about 1millimeter. Practical limitations of handling, mixing, and pumpingequipment in wellbore applications, currently limit the practical uselength of the fibers to about 100 millimeters. Accordingly, in otherembodiments, a range of fiber length will be from about 1 mm to about100 mm or so. In yet other embodiments, the length will be from at leastabout 2 mm up to about 30 mm. Similarly, fiber diameters will preferablyrange upwardly from about 5 microns. In other embodiments, the diameterswill range from about 5 microns to about 40 microns. In otherembodiments, the diameters will range from about 8 microns to about 20microns, depending on the modulus of the fiber, as described more fullyhereinafter. A ratio of length to diameter (assuming the cross sectionof the fiber to be circular) in excess of 50 is preferred. However, thefibers may have a variety of shapes ranging from simple round or ovalcross-sectional areas to more complex shapes such as trilobe, figureeight, star-shape, rectangular cross-sectional, or the like. Preferably,generally straight fibers with round or oval cross sections will beused. Curved, crimped, branched, spiral-shaped, hollow, fibrillated, andother three dimensional fiber geometries may be used. Again, the fibersmay be hooked on one or both ends. Fiber and platelet densities are notcritical, and will preferably range from below 1 to 4 g/cm³ or more.

Those skilled in the art will recognize that a dividing line betweenwhat constitute “platelets”, on one hand, and “fibers”, on the other,tends to be arbitrary, with platelets being distinguished practicallyfrom fibers by having two dimensions of comparable size both of whichare significantly larger than the third dimension, fibers, as indicated,generally having one dimension significantly larger than the other two,which are similar in size. As used herein, the terms “platelet” or“platelets” are employed in their ordinary sense, suggesting flatness orextension in two particular dimensions, rather than in one dimension,and also is understood to include mixtures of both differing types andsizes. In general, shavings, discs, wafers, films, and strips of thepolymeric material(s) may be used. Conventionally, the term “aspectratio” is understood to be the ratio of one dimension, especially adimension of a surface, to another dimension. As used herein, the phraseis taken to indicate the ratio of the diameter of the surface area ofthe largest side of a segment of material, treating or assuming suchsegment surface area to be circular, to the thickness of the material(on average). Accordingly, the platelets utilized in the invention willpossess an average aspect ratio of from about 10 to about 10,000. Incertain embodiments the average aspect ration is from 100 to 1000. Inother embodiments, the platelets will be larger than 5 microns in theshortest dimension, the dimensions of a platelet which may be used inthe invention being, for example, 6 mm×2 mm×15 μm.

In a particularly advantageous aspect of the invention, particle size ofthe organic polymeric particulate matter may be managed or adjusted toadvance or retard the reaction or degradation of the gelled suspensionin the fracture. Thus, for example, of the total particulate mattercontent, 20 percent may comprise larger particles, e.g., greater than100 microns, and 80 percent smaller, say 80 percent smaller than 20micron particles. Such blending in the gelled suspension may provide,because of surface area considerations, a different time of completionof reaction or decomposition of the particulate matter, and hence thetime of completion of gel decomposition or breaking, when compared withthat provided by a different particle size distribution.

The solid particulate matter, e.g., fibers, or fibers and/or platelet,containing fluid suspensions used in the invention may be prepared inany suitable manner or in any sequence or order. Thus, the suspensionmay be provided by blending in any order at the surface, and byaddition, in suitable proportions, of the components to the fluid orslurry during treatment on the fly. The suspensions may also be blendedoffsite. In the case of some materials, which are not readilydispersible, the fibers should be “wetted” with a suitable fluid, suchas water or a wellbore fluid, before or during mixing with thefracturing fluid, to allow better feeding of the fibers. Good mixingtechniques should be employed to avoid “clumping” of the particulatematter.

Erodible Particles and Fibers

Suitable dissolvable, degradable, or erodible proppants include, withoutlimitation, water-soluble solids, hydrocarbon-soluble solids, ormixtures and combinations thereof. Exemplary examples of water-solublesolids and hydrocarbon-soluble solids include, without limitation, salt,calcium carbonate, wax, soluble resins, polymers, or mixtures andcombinations thereof. Exemplary salts include, without limitation,calcium carbonate, benzoic acid, naphthalene based materials, magnesiumoxide, sodium bicarbonate, sodium chloride, potassium chloride, calciumchloride, ammonium sulfate, or mixtures and combinations thereof.Exemplary polymers include, without limitation, polylactic acid (PLA),polyglycolic acid (PGA), lactic acid/glycolic acid copolymer (PLGA),polysaccharides, starches, or mixtures and combinations thereof.

As used herein, “polymers” includes both homopolymers and copolymers ofthe indicated monomer with one or more comonomers, including graft,block and random copolymers. The polymers may be linear, branched, star,crosslinked, derivatized, and so on, as desired. The dissolvable orerodible proppants may be selected to have a size and shape similar ordissimilar to the size and shape of the proppant particles as needed tofacilitate segregation from the proppant. Dissolvable, degradable, orerodible proppant particle shapes can include, for example, spheres,rods, platelets, ribbons, and the like and combinations thereof. In someapplications, bundles of dissolvable, degradable, or erodible fibers, orfibrous or deformable materials, may be used.

The dissolvable, degradable, or erodible proppants may be capable ofdecomposing in the water-based fracturing fluid or in the downholefluid, such as fibers made of polylactic acid (PLA), polyglycolic acid(PGA), polyvinyl alcohol (PVOH), and others. The dissolvable,degradable, or erodible fibers may be made of or coated by a materialthat becomes adhesive at subterranean formation temperatures. Thedissolvable, degradable, or erodible fibers used in one embodiment maybe up to 2 mm long with a diameter of 10-200 microns, in accordance withthe main condition that the ratio between any two of the threedimensions be greater than 5 to 1. In another embodiment, thedissolvable, degradable, or erodible fibers may have a length greaterthan 1 mm, such as, for example, 1-30 mm, 2-25 mm or 3-18 mm, e.g.,about 6 mm; and they can have a diameter of 5-100 microns and/or adenier of about 0.1-20, preferably about 0.15-6. These dissolvable,degradable, or erodible fibers are desired to facilitate proppantcarrying capability of the treatment fluid with reduced levels of fluidviscosifying polymers or surfactants. Dissolvable, degradable, orerodible fiber cross-sections need not be circular and fibers need notbe straight. If fibrillated dissolvable, degradable, or erodible fibersare used, the diameters of the individual fibrils maybe much smallerthan the aforementioned fiber diameters.

Other Fracturing Fluid Components

The fracturing fluid may also include ester compound such as esters ofpolycarboxylic acids. For example, the ester compound may be an ester ofoxalate, citrate, or ethylene diamine tetraacetate. The ester compoundhaving hydroxyl groups can also be acetylated. An example of this isthat citric acid can be acetylated to form acetyl triethyl citrate. Apresently preferred ester is acetyl triethyl citrate.

Gases

Suitable gases for foaming the foamable, ionically coupled gelcomposition include, without limitation, nitrogen, carbon dioxide, orany other gas suitable for use in formation fracturing, or mixtures orcombinations thereof.

Corrosion Inhibitors

Suitable corrosion inhibitor for use in this invention include, withoutlimitation: quaternary ammonium salts e.g., chloride, bromides, iodides,dimethylsulfates, diethylsulfates, nitrites, bicarbonates, carbonates,hydroxides, alkoxides, or the like, or mixtures or combinations thereof;salts of nitrogen bases; or mixtures or combinations thereof. Exemplaryquaternary ammonium salts include, without limitation, quaternaryammonium salts from an amine and a quaternarization agent, e.g.,alkylchlorides, alkylbromide, alkyl iodides, alkyl sulfates such asdimethyl sulfate, diethyl sulfate, etc., dihalogenated alkanes such asdichloroethane, dichloropropane, dichloroethyl ether, epichlorohydrinadducts of alcohols, ethoxylates, or the like; or mixtures orcombinations thereof and an amine agent, e.g., alkylpyridines,especially, highly alkylated alkylpyridines, alkyl quinolines, C6 to C24synthetic tertiary amines, amines derived from natural products such ascoconuts, or the like, dialkylsubstituted methyl amines, amines derivedfrom the reaction of fatty acids or oils and polyamines,amidoimidazolines of DETA and fatty acids, imidazolines ofethylenediamine, imidazolines of diaminocyclohexane, imidazolines ofaminoethylethylenediamine, pyrimidine of propane diamine and alkylatedpropene diamine, oxyalkylated mono and polyamines sufficient to convertall labile hydrogen atoms in the amines to oxygen containing groups, orthe like or mixtures or combinations thereof. Exemplary examples ofsalts of nitrogen bases, include, without limitation, salts of nitrogenbases derived from a salt, e.g.: C1 to C8 monocarboxylic acids such asformic acid, acetic acid, propanoic acid, butanoic acid, pentanoic acid,hexanoic acid, heptanoic acid, octanoic acid, 2-ethylhexanoic acid, orthe like; C2 to C12 dicarboxylic acids, C2 to C12 unsaturated carboxylicacids and anhydrides, or the like; polyacids such as diglycolic acid,aspartic acid, citric acid, or the like; hydroxy acids such as lacticacid, itaconic acid, or the like; aryl and hydroxy aryl acids; naturallyor synthetic amino acids; thioacids such as thioglycolic acid (TGA);free acid forms of phosphoric acid derivatives of glycol, ethoxylates,ethoxylated amine, or the like, and aminosulfonic acids; or mixtures orcombinations thereof and an amine, e.g.: high molecular weight fattyacid amines such as cocoamine, tallow amines, or the like; oxyalkylatedfatty acid amines; high molecular weight fatty acid polyamines (di, tri,tetra, or higher); oxyalkylated fatty acid polyamines; amino amides suchas reaction products of carboxylic acid with polyamines where theequivalents of carboxylic acid is less than the equivalents of reactiveamines and oxyalkylated derivatives thereof; fatty acid pyrimidines;monoimidazolines of EDA, DETA or higher ethylene amines, hexamethylenediamine (HMDA), tetramethylenediamine (TMDA), and higher analogsthereof; bisimidazolines, imidazolines of mono and polyorganic acids;oxazolines derived from monoethanol amine and fatty acids or oils, fattyacid ether amines, mono and bis amides of aminoethylpiperazine; GAA andTGA salts of the reaction products of crude tall oil or distilled talloil with diethylene triamine; GAA and TGA salts of reaction products ofdimer acids with mixtures of poly amines such as TMDA, HMDA and1,2-diaminocyclohexane; TGA salt of imidazoline derived from DETA withtall oil fatty acids or soy bean oil, canola oil, or the like; ormixtures or combinations thereof.

Other Fracturing Fluid Additives

The fracturing fluids of this invention may also include other additivessuch as pH modifiers, scale inhibitors, carbon dioxide controladditives, paraffin control additives, oxygen control additives, saltinhibitors, or other additives.

pH Modifiers

Suitable pH modifiers for use in this invention include, withoutlimitation, alkali hydroxides, alkali carbonates, alkali bicarbonates,alkaline earth metal hydroxides, alkaline earth metal carbonates,alkaline earth metal bicarbonates, rare earth metal carbonates, rareearth metal bicarbonates, rare earth metal hydroxides, amines,hydroxylamines (NH₂OH), alkylated hydroxyl amines (NH₂OR, where R is acarbyl group having from 1 to about 30 carbon atoms or heteroatoms—O orN), and mixtures or combinations thereof. Preferred pH modifiers includeNaOH, KOH, Ca(OH)₂, CaO, Na₂CO₃, KHCO₃, K₂CO₃, NaHCO₃, MgO, Mg(OH)₂ andmixtures or combinations thereof. Preferred amines includetriethylamine, triproplyamine, other trialkylamines, bis hydroxyl ethylethylenediamine (DGA), bis hydroxyethyl diamine 1-2 dimethylcyclohexane,or the like or mixtures or combinations thereof.

Scale Control

Suitable additives for Scale Control and useful in the compositions ofthis invention include, without limitation: Chelating agents, e.g., Na⁺,K⁺ or NH₄ ⁺ salts of EDTA; Na, K or NH₄ ⁺ salts of NTA; Na⁺, K⁺ or NH₄ ⁺salts of Erythorbic acid; Na⁺, K⁺ or NH₄ ⁺ salts of thioglycolic acid(TGA); Na⁺, K⁺ or NH₄ ⁺ salts of Hydroxy acetic acid; Na⁺, K⁺ or NH₄ ⁺salts of Citric acid; Na⁺, K⁺ or NH₄ ⁺ salts of Tartaric acid or othersimilar salts or mixtures or combinations thereof. Suitable additivesthat work on threshold effects, sequestrants, include, withoutlimitation: Phosphates, e.g., sodium hexamethylphosphate, linearphosphate salts, salts of polyphosphoric acid, Phosphonates, e.g.,nonionic such as HEDP (hydroxythylidene diphosphoric acid), PBTC(phosphoisobutane, tricarboxylic acid), Amino phosphonates of: MEA(monoethanolamine), NH₃, EDA (ethylene diamine), Bishydroxyethylenediamine, Bisaminoethylether, DETA (diethylenetriamine), HMDA(hexamethylene diamine), Hyper homologues and isomers of HMDA,Polyamines of EDA and DETA, Diglycolamine and homologues, or similarpolyamines or mixtures or combinations thereof; Phosphate esters, e.g.,polyphosphoric acid esters or phosphorus pentoxide (P₂O₅) esters of:alkanol amines such as MEA, DEA, triethanol amine (TEA),Bishydroxyethylethylene diamine; ethoxylated alcohols, glycerin, glycolssuch as EG (ethylene glycol), propylene glycol, butylene glycol,hexylene glycol, trimethylol propane, pentaerythritol, neopentyl glycolor the like; Tris & Tetra hydroxy amines; ethoxylated alkyl phenols(limited use due to toxicity problems), Ethoxylated amines such asmonoamines such as MDEA and higher amines from 2 to 24 carbons atoms,diamines 2 to 24 carbons carbon atoms, or the like; Polymers, e.g.,homopolymers of aspartic acid, soluble homopolymers of acrylic acid,copolymers of acrylic acid and methacrylic acid, terpolymers ofacylates, AMPS, etc., hydrolyzed polyacrylamides, poly malic anhydride(PMA); or the like; or mixtures or combinations thereof.

Carbon Dioxide Neutralization

Suitable additives for CO₂ neutralization and for use in thecompositions of this invention include, without limitation, MEA, DEA,isopropylamine, cyclohexylamine, morpholine, diamines,dimethylaminopropylamine (DMAPA), ethylene diamine, methoxy proplyamine(MOPA), dimethylethanol amine, methyldiethanolamine (MDEA) & oligomers,imidazolines of EDA and homologues and higher adducts, imidazolines ofaminoethylethanolamine (AEEA), aminoethylpiperazine, aminoethylethanolamine, di-isopropanol amine, DOW AMP-90™, Angus AMP-95, dialkylamines(of methyl, ethyl, isopropyl), mono alkylamines (methyl, ethyl,isopropyl), trialkyl amines (methyl, ethyl, isopropyl),bishydroxyethylethylene diamine (THEED), or the like or mixtures orcombinations thereof.

Paraffin Control

Suitable additives for Paraffin Removal, Dispersion, and/or paraffinCrystal Distribution include, without limitation: Cellosolves availablefrom DOW Chemicals Company; Cellosolve acetates; Ketones; Acetate andFormate salts and esters; surfactants composed of ethoxylated orpropoxylated alcohols, alkyl phenols, and/or amines; methylesters suchas coconate, laurate, soyate or other naturally occurring methylestersof fatty acids; sulfonated methylesters such as sulfonated coconate,sulfonated laurate, sulfonated soyate or other sulfonated naturallyoccurring methylesters of fatty acids; low molecular weight quaternaryammonium chlorides of coconut oils soy oils or C₁₀ to C₂₄ amines ormonohalogenated alkyl and aryl chlorides; quanternary ammonium saltscomposed of disubstituted (e.g., dicoco, etc.) and lower molecularweight halogenated alkyl and/or aryl chlorides; gemini quaternary saltsof dialkyl (methyl, ethyl, propyl, mixed, etc.) tertiary amines anddihalogenated ethanes, propanes, etc. or dihalogenated ethers such asdichloroethyl ether (DCEE), or the like; gemini quaternary salts ofalkyl amines or amidopropyl amines, such as cocoamidopropyldimethyl, bisquaternary ammonium salts of DCEE; or mixtures or combinations thereof.Suitable alcohols used in preparation of the surfactants include,without limitation, linear or branched alcohols, specially mixtures ofalcohols reacted with ethylene oxide, propylene oxide or higheralkyleneoxide, where the resulting surfactants have a range of HLBs.Suitable alkylphenols used in preparation of the surfactants include,without limitation, nonylphenol, decylphenol, dodecylphenol or otheralkylphenols where the alkyl group has between about 4 and about 30carbon atoms. Suitable amines used in preparation of the surfactantsinclude, without limitation, ethylene diamine (EDA), diethylenetriamine(DETA), or other polyamines. Exemplary examples include Quadrols,Tetrols, Pentrols available from BASF. Suitable alkanolamines include,without limitation, monoethanolamine (MEA), diethanolamine (DEA),reactions products of MEA and/or DEA with coconut oils and acids.

Oxygen Control

The introduction of water downhole often is accompanied by an increasein the oxygen content of downhole fluids due to oxygen dissolved in theintroduced water. Thus, the materials introduced downhole must work inoxygen environments or must work sufficiently well until the oxygencontent has been depleted by natural reactions. For system that cannottolerate oxygen, then oxygen must be removed or controlled in anymaterial introduced downhole. The problem is exacerbated during thewinter when the injected materials include winterizers such as water,alcohols, glycols, Cellosolves, formates, acetates, or the like andbecause oxygen solubility is higher to a range of about 14-15 ppm invery cold water. Oxygen can also increase corrosion and scaling. In CCT(capillary coiled tubing) applications using dilute solutions, theinjected solutions result in injecting an oxidizing environment (0₂)into a reducing environment (CO₂, H₂S, organic acids, etc.).

Options for controlling oxygen content includes: (1) de-aeration of thefluid prior to downhole injection, (2) addition of normal sulfides toproduct sulfur oxides, but such sulfur oxides can accelerate acid attackon metal surfaces, (3) addition of erythorbates, ascorbates,diethylhydroxyamine or other oxygen reactive compounds that are added tothe fluid prior to downhole injection; and (4) addition of corrosioninhibitors or metal passivation agents such as potassium (alkali) saltsof esters of glycols, polyhydric alcohol ethyloxylates or other similarcorrosion inhibitors. Exemplary examples oxygen and corrosion inhibitingagents include mixtures of tetramethylene diamines, hexamethylenediamines, 1,2-diaminecyclohexane, amine heads, or reaction products ofsuch amines with partial molar equivalents of aldehydes. Other oxygencontrol agents include salicylic and benzoic amides of polyamines, usedespecially in alkaline conditions, short chain acetylene diols orsimilar compounds, phosphate esters, borate glycerols, urea and thioureasalts of bisoxalidines or other compound that either absorb oxygen,react with oxygen or otherwise reduce or eliminate oxygen.

Salt Inhibitors

Suitable salt inhibitors for use in the fluids of this inventioninclude, without limitation, Na Minus Nitrilotriacetamide available fromClearwater International, LLC of Houston, Tex.

DETAILED DESCRIPTION OF THE DRAWINGS

Referring now to FIG. 1A, an embodiment of a fracturing pulse or slugsequence, generally 100, is shown to include a pad stage 102 having apad duration t_(pad), a proppant placement stage 104 having a proppantplacement duration t_(pp), and a tail-in stage 106 having a tail-induration t_(t). The proppant placement stage 104 includes foursub-stages 108, 110, 112, and 114, each sub-stage 108, 110, 112, and 114include two proppant-free fluid pulses 108 a&b, 110 a&b, 112 a&b, and114 a&b and two proppant-containing fluid pulses 108 c&d, 110 c&d, 112c&d, and 114 c&d. Each sub-stage 108, 110, 112, and 114 is described bya pulse cycle duration t_(pcycle). The pulse cycle duration t_(pcycle)includes a proppant-containing fluid pulse duration t_(pcp) and aproppant-free fluid pulse duration t_(pfp), where the durationst_(pcycle), t_(pcp), and t_(pfp) may be the same or different for eachsub-stage 108, 110, 112, and 114 and the durations t_(pcp) and t_(pfp)in each cycle may be the same or different.

Referring now to FIG. 1B, another embodiment of a fracturing pulse orslug sequence, generally 120, is shown to include a pad stage 122 havinga pad duration t_(pad), a proppant placement stage 124 having a proppantplacement duration t_(pp), and a tail-in stage 126 having a tail-induration t_(t). The proppant placement stage 124 includes foursub-stages 128, 130, 132, and 134, each sub-stage 128, 130, 132, and 134include a plurality of sinusoidal proppant-free fluid pulses 128 a-c,130 a-c, 132 a-c, and 134 a-c and a plurality of sinusoidalproppant-containing fluid pulses 128 e-g, 130 e-g, 132 e-g, and 134 e-g.Each sub-stage 128, 130, 132, and 134 is described by a sinusoidal pulsecycle duration t_(pcycle). The pulse cycle durations t_(pcycle) may bethe same or different for each sub-stage 128, 130, 132, and 134 anddurations of the sinusoidal proppant-containing phases and durations ofthe sinusoidal proppant-free phases in each cycle may be the same ordifferent.

Referring now to FIG. 1C, another embodiment of a fracturing pulse orslug sequence, generally 140, is shown to include a pad stage 142 havinga pad duration t_(pad), a proppant placement stage 144 having a proppantplacement duration t_(pp), and a tail-in stage 146 having a tail-induration t_(t). The proppant placement stage 144 is shown here as acontinuous increasing volume ramp. The ramp 144 includes a plurality ofproppant-free fluid pulses 144 a-h and a plurality ofproppant-containing fluid pulses 104 i-o. Each of theproppant-containing fluid pulses 104 i-o comprises an aggregatingcomposition or an aggregating composition and a coating crosslinkingcomposition pulse, which may be centered in the proppant-containingfluid pulses 104 i-o sub-stage 108, 110, 112, and 114 is described by apulse cycle duration t_(pcycle). The pulse cycle duration t_(pcycle)includes a proppant-containing fluid pulse duration t_(pcp) and aproppant-free fluid pulse duration t_(pfp), where the durationst_(pcycle), t_(pcp), and t_(pfp) may be the same or different for eachsub-stage 108, 110, 112, and 114 and the durations t_(pcp) and t_(pfp)in each cycle may be the same or different.

Referring now to FIG. 1D, another embodiment of a fracturing pulse orslug sequence, generally 160, is shown to include a pad stage 162 havinga pad duration t_(pad), a proppant placement stage 164 having a proppantplacement duration t_(pp), and a tail-in stage 166 having a tail-induration t_(t). The proppant placement stage 164 is shown here as acontinuous increasing volume ramp. The ramp 164 includes a continuousincreasing proppant-containing fluid injection 164 a and a plurality ofan aggregating composition or an aggregating composition and a coatingcrosslinking composition pulses 164 b-h. Each of the pulses 164 b-h maybe of the same or different duration.

Referring now to FIG. 2A, an embodiment of a proppant patternestablished in a formation penetrated by a well bore by a proppantplacement stage, generally 200, is shown to include a well bore 202penetrating a formation 204. The well bore 202 includes a cemented oruncemented casing string 206 and a broad fracture 208 formed in theformation 204 through a plurality of perforations 210 in the string 206by a viscosified pad fluid injected into the formation 204 at asufficient pressure to form the fracture 208. The fracture 208 includesa proppant pattern 212 formed by the proppant placement stage 200including a plurality of proppant-free fluid pulses 214 a-h and analternating plurality of proppant-containing fluid pulses 216 a-g. Theproppant pattern 212 comprises a set of proppant networks 218 a-gincluding proppant pillars 220 a-g and flow pathways 222 a-g. Theproppant-containing fluid pulses 216 a-g have the same or differentproppant compositions (shown here as different) giving rise to the sameor different proppant pillars 218 a-g (shown here as different), wherethe proppant-containing fluid pulse proppant compositions differ in atleast one proppant composition property including proppant type,proppant size, proppant shape, and concentrations of each proppant type,size, shape, or mixtures thereof and mixtures or combinations thereof.

Referring now to FIG. 2B, an embodiment of a proppant patternestablished in a formation penetrated by a well bore by a proppantplacement stage, generally 200, is shown to include a well bore 202penetrating a formation 204. The well bore 202 includes a cemented oruncemented casing string 206 and a narrow fracture 208 formed in theformation 204 through a plurality of perforations 210 in the string 206by a viscosified pad fluid injected into the formation 204 at asufficient pressure to form the fracture 208. The fracture 208 includesa proppant pattern 212 formed by the proppant placement stage 200including a plurality of proppant-free fluid pulses 214 a-g and analternating plurality of proppant-containing fluid pulses 216 a-f. Theproppant pattern 212 comprises a set of proppant networks 218 a-fincluding proppant pillars 220 a-f and flow pathways 222 a-f. Theproppant-containing fluid pulses 216 a-f have the same or differentproppant compositions (shown here as different) giving rise to the sameor different proppant pillars 220 a-f (shown here as different), wherethe proppant-containing fluid pulse proppant compositions differ in atleast one proppant composition property including proppant type,proppant size, proppant shape, and concentrations of each proppant type,size, shape, or mixtures thereof and mixtures or combinations thereof.

Referring now to FIG. 2C, an embodiment of a proppant patternestablished in a formation penetrated by a well bore by a proppantplacement stage, generally 200, is shown to include a well bore 202penetrating a formation 204. The well bore 202 includes a cemented oruncemented casing string 206 and a illustrative square fracture 208formed in the formation 204 through a plurality of perforations 210 inthe string 206 by a viscosified pad fluid injected into the formation204 at a sufficient pressure to form the fracture 208. The fracture 208includes a proppant pattern 212 formed by the proppant placement stage200 including a plurality of proppant-free fluid pulses 214 a-e and analternating plurality of proppant-containing fluid pulses 216 a-f. Theproppant pattern 212 comprises a set of proppant networks 218 a-fincluding proppant pillar groups 220 a-f and major flow pathways 222 a-fand minor flow pathways within pillar groups (not shown, but evidentfrom the groups). The proppant-containing fluid pulses 216 a-f have thesame or different proppant compositions (shown here as different) givingrise to the same or different proppant pillars 220 a-f (shown here asdifferent), where the proppant-containing fluid pulse proppantcompositions differ in at least one proppant composition propertyincluding proppant type, proppant size, proppant shape, andconcentrations of each proppant type, size, shape, or mixtures thereofand mixtures or combinations thereof.

Referring now to FIG. 2D, an embodiment of a proppant patternestablished in a formation penetrated by a well bore by a proppantplacement stage, generally 200, is shown to include a well bore 202penetrating a formation 204. The well bore 202 includes a cemented oruncemented casing string 206 and a highly branched fracture 208 formedin the formation 204 through perforations 210 in the string 206 by aviscosified pad fluid injected into the formation 204 at a sufficientpressure to form the fracture 208. The fracture 208 includes a proppantpattern 212 formed by the proppant placement stage 200 including aplurality of proppant-free fluid pulses 214 and an alternating pluralityof proppant-containing fluid pulses 216. The proppant pattern 212comprises proppant pillars 218 and flow pathways within pillar groups(not shown). The proppant-containing fluid pulses 216 may have the sameor different proppant compositions (shown here as different) giving riseto the same or different proppant pillars 218 (shown here as different),where the proppant-containing fluid pulse proppant compositions differin at least one proppant composition property including proppant type,proppant size, proppant shape, and concentrations of each proppant type,size, shape, or mixtures thereof and mixtures or combinations thereof.

Referring now to FIG. 2E, an embodiment of a frac pack patternestablished in a formation penetrated by a well bore, generally 200, isshown to include a well bore 202 penetrating a formation 204. The wellbore 202 includes a cemented or uncemented casing string 206 and a fracpack 208 formed in the formation 204 through a plurality of perforations210 in the string 206 by a viscosified proppant-containing fluidinjected into the formation 204 at a sufficient pressure to form thefrac pack 208. The frac pack 208 includes a proppant pillar pattern 212including a plurality of proppant pillars 214 and a plurality of flowpathways 216 therethrough.

Referring now to FIGS. 3A-I, nine different pillar configurations areillustrated, each configuration including different proppant types indifferent arrangements. Looking at FIG. 3A, a regular proppantconfiguration 300 is shown to include treated solid proppant particles302 having an aggregating composition coating 304 thereon. Looking atFIG. 3B, an irregular proppant configuration 306 is shown to includetreated solid proppant particles 308 having an aggregating compositioncoating 310 thereon and hollow untreated proppant particles 312. Lookingat FIG. 3C, another irregular proppant configuration 314 is shown toinclude treated hollow proppant particles 316 having an aggregatingcomposition coating 318 thereon and solid untreated proppant particles320. Looking at FIG. 3D, another irregular proppant configuration 322 isshown to include two different sized treated solid proppant particles324 and 326 having an aggregating composition coating 328 and 330thereon. Looking at FIG. 3E, another irregular proppant configuration332 is shown to include treated solid regular shaped proppant particles334 having an aggregating composition coating 336 thereon, treated solidirregular shaped proppant particles 338 having an aggregatingcomposition coating 340 thereon, and untreated solid regular proppantparticles 342. Looking at FIG. 3F, another irregular proppantconfiguration 344 is shown to include treated solid regular proppantparticles 346 having an aggregating composition coating 348 thereon anduntreated solid regular proppant particles 350. Looking at FIG. 3G,another regular proppant configuration 352 is shown to include treatedsolid regular proppant particles 354 having an aggregating compositioncoating 356 thereon and a non-erodible fibers 358 entangled with andpartially surrounding the cluster. Looking at FIG. 3H, another irregularproppant configuration 360 is shown to include treated solid regularproppant particles 362 having an aggregating composition coating 364thereon and untreated solid regular proppant particles 366 and anentangled non-erodible fiber 368. Looking at FIG. 3I, another irregularproppant configuration 370 is shown to include treated solid regularproppant particles 372 having an aggregating composition coating 374thereon and untreated hollow regular proppant particles 376 andsurrounding non-erodible fibers 378. Of course, it should be recognizedthat any given fracturing application may include any of this proppantgroups in any relative proportions.

Referring now to FIGS. 4A-J, ten different pillar groups areillustrated, each group including four pillars, each figure having adifferent proppant pillar type differing in proppant particle type andpillar pillar configuration. Looking at FIG. 4A, a pillar groupconfiguration 400 is shown to include four irregular proppant pillars402 including treated solid regular proppant particles 404 and untreatedregular proppant particles 406. Looking at FIG. 4B, another pillar groupconfiguration 408 is shown to include four regular proppant pillars 410including treated solid regular proppant particles 412. Looking at FIG.4C, a pillar group configuration 414 is shown to include four irregularproppant pillars 416 including treated solid regular proppant particles418 and untreated hollow regular proppant particles 420. Looking at FIG.4D, a pillar group configuration 422 is shown to include four irregularproppant pillars 424 including treated solid regular proppant particles426, treated solid irregular proppant particle 428 and untreated regularproppant particles 430. Looking at FIG. 4E, a pillar group configuration432 is shown to include four irregular proppant pillars 434 includingtwo different sized treated solid proppant particles 436 and 438.Looking at FIG. 4F, a pillar group configuration 440 is shown to includefour irregular proppant pillars 442 including treated hollow regularproppant particles 444 and untreated solid regular proppant particles446. Looking at FIG. 4G, a pillar group configuration 448 is shown toinclude six different proppant pillar types 450 a-f including differenttreated solid proppant particles 452 and different untreated proppantparticles 454. Looking at FIG. 4H, a pillar group configuration 456 isshown to include two irregular proppant pillar types 458 a&b includingtreated solid regular proppant particles 460 and untreated regularproppant particles 462. Looking at FIG. 4I, a pillar group configuration464 is shown to include two irregular proppant pillar types 466 a&bincluding different treated solid proppant particles 468 and differentuntreated proppant particles 470. Looking at FIG. 4J, a pillar groupconfiguration 472 is shown to include regular and irregular proppantpillar types 474 a&b including different treated solid regular proppantparticles 476 and different untreated particles 478.

Referring now to FIGS. 5A-D, four perforation patterns are illustrated,each pattern including different perforation groups separated bynon-perforation spans. Looking at FIG. 5A, a perforation interval 500 isshown in a well bore 502 that my be cased with a cemented ornon-cemented casing 504. The interval 500 includes two perforationgroups 506 and 508. The perforation group 506 comprises six tightlyspaced perforations 510, while the second group 508 includes a singleperforation 512. Looking at FIG. 5B, a perforation interval 520 is shownin a well bore 522 that my be cased with a cemented or non-cementedcasing 524. The interval 520 includes two perforation groups 526 and528. The perforation group 526 comprises six tightly spaced perforations530, while the second group 528 includes three tightly spacedperforations 532. Looking at FIG. 5C, a perforation interval 540 isshown in a well bore 542 that my be cased with a cemented ornon-cemented casing 544. The interval 540 includes three perforationgroups 546, 548, and 550. The perforation group 546 comprises fivetightly spaced perforations 552; the second group 548 includes threetightly perforations 554; and the third perforation group 550 includesthree tightly perforations 556. Looking at FIG. 5D, a perforationinterval 560 is shown in a well bore 562 that my be cased with acemented or non-cemented casing 564. The interval 560 includes threeperforation groups 566, 568, and 570. The perforation group 566comprises four less tightly spaced perforations 572; the second group568 includes three tightly perforations 574; and the third perforationgroup 570 includes six tightly spaced perforations 576. It should berecognized that the above perforation intervals are simply included asillustrations of different perforation configuration. These intervalsmay be repeated in blocks in patterns to produce long or shortperforation configurations. Additionally, it should be recognized thatdimensions of the perforation may be adjusted so that each group ofperforation will selectively permit different proppant particles sizestherethrough.

Experiments of the Invention

Referring now to FIG. 6, a table is shown that provides zeta potentialranges and corresponding aggregating propensities. Maximal aggregatingpotential or propensity is associated with zeta potentials between +3 mVand −5 mV; strong aggregating potential or propensity is associated withzeta potentials between −5 mV and −10 mV; medium to weak aggregatingpotential or propensity is associated with zeta potentials between −10mV and −15 mV; a threshold aggregating potential or propensity isassociated with zeta potentials between −16 mV and −30 mV; and low orlittle aggregating potential or propensity is associated with zetapotentials between −31 mV and −100 mV or lower.

FIG. 6 also includes experimental data of untreated silica and silicatreated with the aggregating agent SandAid™, an amine-phosphate reactionproduct type aggregating agent available from Weatherford International,which forms a partial or complete coating on the silica altering theaggregating propensity of the treated silica. In fact, untreated silicahave a zeta potential of about −47.85 mV, while the SandAid™ treatedsilica has a zeta potential of about −1.58 mV, thus, changing anon-aggregating proppant into a maximally aggregating proppant.Similarly, untreated coal which as a zeta potential of about −28.37 mV,a threshold aggregating proppant, when treated with SandAid™, theuntreated coal is converted into a treated coal proppant having a zetapotential of about 1.194 mV, converting the threshold aggregatingproppant into a maximally aggregating proppant. By changing the relativeamounts of treated and untreated silica or coal, one may readily adjustthe bulk or relative zeta potential of a proppant composition for usedin the proppant-containing fracturing fluids of this invention.

All references cited herein are incorporated by reference. Although theinvention has been disclosed with reference to its preferredembodiments, from reading this description those of skill in the art mayappreciate changes and modification that may be made which do not departfrom the scope and spirit of the invention as described above andclaimed hereafter.

We claim:
 1. A composition for forming proppants islands within aformation or zone thereof, where the composition comprises: a fracturingfluid containing from about 1 to about 8 lbs of a treated proppant pergal of the fracturing fluid, where the treated proppant comprises aproppant having a partial or complete coating of a zeta potentialaltering composition consisting of an amine-phosphate reaction product;an amine component selected from the group consisting of aniline andalkyl anilines or mixtures of alkyl anilines, pyridines and alkylpyridines or mixtures of alkyl pyridines, pyrrole and alkyl pyrroles ormixtures of alkyl pyrroles, piperidine and alkyl piperidines or mixturesof alkyl piperidines, pyrrolidine and alkyl pyrrolidines or mixtures ofalkyl pyrrolidines, imidazole and alkyl imidazole or mixtures of alkylimidazole, pyrazine and alkyl pyrazine or mixture of alkyl pyrazine,acridine and alkyl acridine or mixture of alkyl acridine, pyrimidine andalkyl pyrimidine or mixture of alkyl pyrimidine, and quinazoline andalkyl quinazoline or mixture of alkyl quinazoline; or mixtures andcombinations thereof.
 2. The proppant islands and composition of claim1, further comprising: an untreated proppant, a non-erodible fiber, andan erodible material comprising erodible particles, erodible fibers, ormixtures and combinations thereof.
 3. A re-healable proppant islandcomprising: a composition for forming proppant islands as claimed inclaim 1, wherein the amount of the treated proppant is sufficient: (a)to allow formation of proppant islands in fractures formed in aformation or zone thereof during fracturing operations and to maintainthe proppant islands substantially intact, if the proppant islandsand/or particles within the proppant islands move within the formationduring and/or after fracturing operations, or during injectionoperations, or during production operations, or (b) to allow formationof proppant islands in fractures formed in a formation or zone thereofduring fracturing operations, to allow the proppant islands to re-healor break apart and reform during and/or after fracturing operations, orduring injection operations, or during production operations maintaininghigh fracture conductivity, and to capture formation fines during and/orafter fracturing operations, or during injection operations, or duringproduction operations.
 4. A self healing proppant island comprising: acomposition for forming a proppant island as claimed in claim 1, whereinthe amount of the treated proppant is sufficient: (a) to allow formationof proppant islands in fractures formed in a formation or zone thereofand to allow the islands to break apart and reform without substantialloss in proppant during and/or after fracturing operations, or duringinjection operations, or during production operations, or (b) to allowformation of proppant islands in fractures formed in a formation or zonethereof, to allow the islands to break apart and reform withoutsubstantial loss in proppant during and/or after fracturing operations,or during injection operations, or during production operations, and tocapture formation fines during and/or after fracturing operations, orduring injection operations, or during production operations.